DAQ-2025-000193

DAQE-AN162310001-25

{{$d1 }}

Casey Murakami
GGUSA Hyrum LLC
4287 Spruill Avenue, Suite 202
North Charleston, SC 29405
[e-mail]

Dear Casey Murakami:

Re: Approval Order: New Hyrum Renewable Natural Gas Facility
Project Number: N162310001

The attached Approval Order (AO) is issued pursuant to the Notice of Intent (NOI) received on August
14, 2024. GGUSA Hyrum LLC must comply with the requirements of this AO, all applicable state
requirements (R307), and Federal Standards.

The project engineer for this action is Christine Bodell, who can be contacted at [phone] or
[e-mail]. Future correspondence on this AO should include the engineer's name as well as the
DAQE number shown on the upper right-hand corner of this letter. No public comments were received on
this action.

Sincerely,

{{$s }}

Bryce C. Bird
Director

BCB:CB:jg

cc: Bear River Health Department

195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
State of Utah

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

January 8, 2025

STATE OF UTAH
Department of Environmental Quality
Division of Air Quality

{{#s=Sig_es_:signer1:signature}}
{{#d1=date1_es_:signer1:date:format(date, "mmmm d, yyyy")}}
{{#d2=date1_es_:signer1:date:format(date, "mmmm d, yyyy"):align(center)}}

APPROVAL ORDER
DAQE-AN162310001-25
New Hyrum Renewable Natural Gas Facility

Prepared By
Christine Bodell, Engineer
[phone]
[e-mail]

Issued to
GGUSA Hyrum LLC - Renewable Natural Gas Facility

Issued On
{{$d2 }}

Issued By

{{$s }}

Bryce C. Bird
Director
Division of Air Quality

January 8, 2025
TABLE OF CONTENTS

TITLE/SIGNATURE PAGE ....................................................................................................... 1
GENERAL INFORMATION ...................................................................................................... 3
CONTACT/LOCATION INFORMATION ............................................................................... 3
SOURCE INFORMATION ........................................................................................................ 3
General Description ................................................................................................................ 3
NSR Classification .................................................................................................................. 3
Source Classification .............................................................................................................. 3
Applicable Federal Standards ................................................................................................. 4
Project Description.................................................................................................................. 4
SUMMARY OF EMISSIONS .................................................................................................... 4
SECTION I: GENERAL PROVISIONS .................................................................................... 4
SECTION II: PERMITTED EQUIPMENT .............................................................................. 5
SECTION II: SPECIAL PROVISIONS ..................................................................................... 6
PERMIT HISTORY ..................................................................................................................... 7
ACRONYMS ................................................................................................................................. 8

DAQE-AN162310001-25
Page 3

GENERAL INFORMATION

CONTACT/LOCATION INFORMATION

Owner Name Source Name
GGUSA Hyrum LLC GGUSA Hyrum LLC - Renewable Natural Gas Facility

Mailing Address Physical Address
4287 Spruill Avenue, Suite 202 410 North 200 West
North Charleston, SC 29405 Hyrum, UT 84319

Source Contact UTM Coordinates
Name: Casey Murakami 428,370 m Easting
Phone: [phone],610,901 m Northing
Email: [e-mail] Datum NAD83
UTM Zone 12
SIC code 1311 (Crude Petroleum & Natural Gas)

SOURCE INFORMATION
General Description
GGUSA Hyrum LLC (GGUSA) has requested to construct a Renewable Natural Gas (RNG) Facility
which will treat the biogas (raw gas) from anaerobic digestors and deliver the treated gas to a natural gas
pipeline distribution system in Hyrum, Cache County. The feed stream for the digestor will be waste from
the adjacent Swift Beef Company, Incorporated (Swift Beef) beef processing plant.

The raw gas from the anaerobic digestors will be sent to a Vacuum Adsorption Vessel, which houses iron
substrate that is used to control H2S content. The gas stream is then sent through a molecular gate
pressure swing adsorption (PSA) skid to remove CO2, H2S, and H2O in a single step. Methane, N2, and O2
pass through the molecular gate as "product gas" and are injected into the pipeline. The removed
contaminants (CO2, H2S, and H2O), known as PSA "tail gas" or "waste gas" will either be sent to the flare
stack for release to ambient air without combustion or combusted for odor control. The flare will utilize
natural gas for a pilot flame and additional natural gas as enrichment gas to ensure combustion.

NSR Classification
New Minor Source

Source Classification
Located in Attainment Area
Cache County
Airs Source Size: B

DAQE-AN162310001-25
Page 4

Applicable Federal Standards
None
Project Description
GGUSA has requested to construct a RNG Facility which will treat the biogas from anaerobic digestors
and deliver the treated gas to a natural gas pipeline distribution system in Hyrum, Cache County. The feed
stream for the anaerobic digestor will be waste from the adjacent Swift Beef processing plant.

Under normal operations, the raw gas from the digestor is treated with an H2S VAV and a PSA skid. The
H2S VAV will reduce H2S in the gas stream to no more than 50 ppm, and the PSA skid will filter out the
remaining H2S, as well as CO2 and H2O. The H2S, CO2, and H2O waste stream is then directed to the flare
stack, where it may or may not be combusted. The flare is utilized as a control device for odor control.
During non-normal operating scenarios, such as emergency or maintenance operations, the RNG plant
will not operate.

SUMMARY OF EMISSIONS

The emissions listed below are an estimate of the total potential emissions from the source. Some
rounding of emissions is possible.

Criteria Pollutant Change (TPY) Total (TPY)
CO2 Equivalent 15961.00
Carbon Monoxide 12.15
Nitrogen Oxides 5.41
Particulate Matter - PM10 0.29
Particulate Matter - PM2.5 0.29
Sulfur Dioxide 1.76
Volatile Organic Compounds 25.87

Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Generic HAPs (CAS #GHAPS) 140
Change (TPY) Total (TPY)
Total HAPs 0.07

SECTION I: GENERAL PROVISIONS

I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101]
I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401] I.3 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1]
DAQE-AN162310001-25
Page 5

I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the two-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of two (2) years. [R307-401-8] I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO,
including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to
the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4]

I.6 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107]
I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]

I.8 The owner/operator shall submit documentation of the status of construction or modification to the Director within 18 months from the date of this AO. This AO may become invalid if construction is not commenced within 18 months from the date of this AO or if construction is discontinued for 18 months or more. To ensure proper credit when notifying the Director, send the documentation to the Director, attn.: NSR Section. [R307-401-18]

SECTION II: PERMITTED EQUIPMENT
II.A THE APPROVED EQUIPMENT II.A.1 Hyrum RNG Facility
II.A.2 One (1) Anaerobic Digestor II.A.3 Two (2) H2S Vacuum Adsorption Vessels (VAV) Arranged in series for operational flexibility
II.A.4 One (1) Molecular Gate (Molegate) PSA Skid Pressure Swing Adsorption II.A.5 One (1) Flare Burner Rating: 40 MMBtu/hr Maximum Inlet Heat Rating: 35.0 MMBtu/hr Burner Fuel: Natural Gas Minimum H2S Destruction Efficiency: 98%

DAQE-AN162310001-25
Page 6

SECTION II: SPECIAL PROVISIONS
II.B REQUIREMENTS AND LIMITATIONS

II.B.1 Site-wide Requirements
II.B.1.a Unless otherwise specified in this AO, the owner/operator shall not allow visible emissions from
any source on site to exceed 10% opacity. [R307-401-8]

II.B.1.a.1 Unless otherwise specified in this AO, opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9. [R307-401-8]
II.B.1.b Unless otherwise specified in this AO, the following terms apply to the operations at the Hyrum
RNG Facility:

"Normal operations" means that the raw gas from the anaerobic digestor is treated by an H2S
VAV and Molecular Gate PSA skid prior to entering the pipeline. All waste/tail gas from the
PSA skid is routed to the flare stack and may or may not be combusted.

"Emergency and/or maintenance operations" means periods of breakdown or maintenance of the
VAVs or PSA skid, or periods of over-production of the anerobic digestor, where the raw gas
from the anaerobic digestor may not be treated by the H2S VAV and/or Molecular Gate PSA skid
prior to entering the pipeline.

[R307-401-8]

II.B.1.c The owner/operator shall not produce more than 171.2 million standard cubic feet (MMscf) of waste (tail) gas per rolling 12-month period during normal operations. [R307-401-8]
II.B.1.c.1 The owner/operator shall:

A. Determine production with flow meters

B. Record production on a daily basis

C. Use the production data to calculate a new rolling 12-month total by the 20th
day of each month using data from the previous 12 months

D. Keep the production records for all periods the plant is in operation.

[R307-401-8]

II.B.1.d The owner/operator shall not operate the Hyrum RNG Facility during emergency and/or maintenance operations. [R307-401-8]
II.B.2 H2S VAV Requirements
II.B.2.a During normal operations, the owner/operator shall route all raw gas streams from the anaerobic digestor through an H2S VAV prior to entering the Molegate PSA skid. [R307-401-8]
II.B.2.b The owner/operator shall install two (2) H2S VAVs that are each certified to meet a H2S emission
concentration of 50 ppm or less. [R307-401-8]
II.B.2.b.1 To demonstrate compliance with the above condition, the owner/operator shall maintain records of the manufacturer's emissions guarantee for the installed H2S VAVs. [R307-401-8]

DAQE-AN162310001-25
Page 7

II.B.3 Flare Requirements II.B.3.a The owner/operator shall install a flare that is certified to meet a VOC and H2S destruction
efficiency of no less than 98% each. [R307-401-8]
II.B.3.a.1 To demonstrate compliance with the above condition, the owner/operator shall maintain records of the manufacturer's emissions guarantee for the installed flare. [R307-401-8] II.B.3.b The owner/operator shall operate the flare according to the manufacturer's recommendations. [R307-401-8]

II.B.3.c The flare shall be equipped with an auto-igniter. [R307-401-8] II.B.3.c.1 The owner or operator shall maintain records demonstrating the date of installation and
manufacturer specifications for the auto-igniter required under R307-503-4. [R307-503-4]
II.B.3.d The flare shall operate with no visible emissions. [R307-401-8]
II.B.3.d.1 Opacity observations of emissions from the flare shall be conducted according to 40 CFR 60, Appendix A, Method 22. [R307-401-8]

PERMIT HISTORY

This Approval Order shall supersede (if a modification) or will be based on the following documents:
Is Derived From NOI dated August 14, 2024 Incorporates Additional Information dated August 28, 2024 Incorporates Additional Information dated October 3, 2024 Incorporates DAQE-MN162310001-24 dated October 9, 2024 Incorporates Additional Information dated October 15, 2024
DAQE-AN162310001-25
Page 8

ACRONYMS

The following lists commonly used acronyms and associated translations as they apply to this document:

40 CFR Title 40 of the Code of Federal Regulations
AO Approval Order
BACT Best Available Control Technology
CAA Clean Air Act
CAAA Clean Air Act Amendments
CDS Classification Data System (used by Environmental Protection Agency to classify
sources by size/type)
CEM Continuous emissions monitor
CEMS Continuous emissions monitoring system
CFR Code of Federal Regulations
CMS Continuous monitoring system
CO Carbon monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent - Title 40 of the Code of Federal Regulations Part 98,
Subpart A, Table A-1
COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality
DAQE This is a document tracking code for internal Division of Air Quality use
EPA Environmental Protection Agency
FDCP Fugitive dust control plan
GHG Greenhouse Gas(es) - Title 40 of the Code of Federal Regulations 52.21 (b)(49)(i)
GWP Global Warming Potential - Title 40 of the Code of Federal Regulations Part 86.1818-
12(a)
HAP or HAPs Hazardous air pollutant(s)
ITA Intent to Approve
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent
NOx Oxides of nitrogen
NSPS New Source Performance Standard
NSR New Source Review
PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size
PSD Prevention of Significant Deterioration
PTE Potential to Emit
R307 Rules Series 307
R307-401 Rules Series 307 - Section 401
SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act
Title V Title V of the Clean Air Act
TPY Tons per year
UAC Utah Administrative Code
VOC Volatile organic compounds

DAQE-IN162310001-24

November 27, 2024

Casey Murakami
GGUSA Hyrum LLC
4287 Spruill Avenue, Suite 202
North Charleston, SC 29405
[e-mail]

Dear Casey Murakami:

Re: Intent to Approve: New Hyrum Renewable Natural Gas Facility
Project Number: N162310001

The attached document is the Intent to Approve (ITA) for the above-referenced project. The ITA is
subject to public review. Any comments received shall be considered before an Approval Order (AO) is
issued. The Division of Air Quality is authorized to charge a fee for reimbursement of the actual costs
incurred in the issuance of an AO. An invoice will follow upon issuance of the final AO.

Future correspondence on this ITA should include the engineer's name, Christine Bodell, as well as the
DAQE number as shown on the upper right-hand corner of this letter. Christine Bodell, can be reached at
[phone] or [e-mail], if you have any questions.

Sincerely,

{{$s }}

Alan D. Humpherys, Manager
New Source Review Section

ADH:CB:jg

cc: Bear River Health Department

195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
State of Utah

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

STATE OF UTAH
Department of Environmental Quality
Division of Air Quality

INTENT TO APPROVE
DAQE-IN162310001-24
New Hyrum Renewable Natural Gas (RNG) Facility

Prepared By
Christine Bodell, Engineer
[phone]
[e-mail]

Issued to
GGUSA Hyrum LLC - Renewable Natural Gas Facility

Issued On
November 27, 2024

{{$s }}

New Source Review Section Manager
Alan D. Humpherys
{{#s=Sig_es_:signer1:signature}}

TABLE OF CONTENTS

TITLE/SIGNATURE PAGE ....................................................................................................... 1
GENERAL INFORMATION ...................................................................................................... 3
CONTACT/LOCATION INFORMATION ............................................................................... 3
SOURCE INFORMATION ........................................................................................................ 3
General Description ................................................................................................................ 3
NSR Classification .................................................................................................................. 3
Source Classification .............................................................................................................. 3
Applicable Federal Standards ................................................................................................. 4
Project Description.................................................................................................................. 4
SUMMARY OF EMISSIONS .................................................................................................... 4
PUBLIC NOTICE STATEMENT............................................................................................... 4
SECTION I: GENERAL PROVISIONS .................................................................................... 5
SECTION II: PERMITTED EQUIPMENT .............................................................................. 6
SECTION II: SPECIAL PROVISIONS ..................................................................................... 6
PERMIT HISTORY ..................................................................................................................... 8
ACRONYMS ................................................................................................................................. 9

DAQE-IN162310001-24
Page 3

GENERAL INFORMATION

CONTACT/LOCATION INFORMATION

Owner Name Source Name
GGUSA Hyrum LLC GGUSA Hyrum LLC - Renewable Natural Gas Facility

Mailing Address Physical Address
4287 Spruill Avenue, Suite 202 410 North 200 West
North Charleston, SC 29405 Hyrum, UT 84319

Source Contact UTM Coordinates
Name: Casey Murakami 428,370 m Easting
Phone: [phone],610,901 m Northing
Email: [e-mail] Datum NAD83
UTM Zone 12
SIC code 1311 (Crude Petroleum & Natural Gas)

SOURCE INFORMATION
General Description
GGUSA Hyrum LLC (GGUSA) has requested to construct a Renewable Natural Gas (RNG) Facility
which will treat the biogas (raw gas) from anaerobic digestors and deliver the treated gas to a natural gas
pipeline distribution system in Hyrum, Cache County. The feed stream for the digestor will be waste from
the adjacent Swift Beef Company, Incorporated (Swift Beef) beef processing plant.

The raw gas from the anaerobic digestors will be sent to a Vacuum Adsorption Vessel (VAV), which
houses iron substrate that is used to control hydrogen sulfide (H2S) content. The gas stream is then sent
through a molecular gate (Molegate) pressure swing adsorption (PSA) skid to remove CO2, H2S, and H2O
in a single step. Methane, N2, and O2 pass through the molecular gate as "product gas" and is injected into
the pipeline. The removed contaminants (CO2, H2S, and H2O), known as PSA "tail gas" or "waste gas,"
will either be sent to the flare stack for release to ambient air without combustion or combusted for odor
control. The flare will utilize natural gas for a pilot flame and additional natural gas as enrichment gas to
ensure combustion.
NSR Classification
New Minor Source

Source Classification
Located in Attainment Area
Cache County
Airs Source Size: B

DAQE-IN162310001-24
Page 4

Applicable Federal Standards
None
Project Description
GGUSA has requested to construct a RNG facility that will treat the biogas (raw gas) from anaerobic
digestors and deliver the treated gas to a natural gas pipeline distribution system in Hyrum, Cache
County. The feed stream for the anaerobic digestor will be waste from the adjacent Swift Beef processing
plant.

Under normal operations, the raw gas from the digestor is treated with an H2S VAV and a PSA skid. The
H2S VAV will reduce H2S in the gas stream to no more than 50 ppm, and the PSA skid will filter out the
remaining H2S, as well as CO2 and H2O. The H2S, CO2, and H2O waste stream is then directed to the flare
stack, where it may or may not be combusted. The flare is utilized as a control device for odor control.
During non-normal operating scenarios, such as emergency or maintenance operations, the RNG plant
will not operate.

SUMMARY OF EMISSIONS

The emissions listed below are an estimate of the total potential emissions from the source. Some
rounding of emissions is possible.

Criteria Pollutant Change (TPY) Total (TPY)
CO2 Equivalent 15961.00
Carbon Monoxide 12.15
Nitrogen Oxides 5.41
Particulate Matter - PM10 0.29
Particulate Matter - PM2.5 0.29
Sulfur Dioxide 1.76
Volatile Organic Compounds 25.87

Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Generic HAPs (CAS #GHAPS) 140
Change (TPY) Total (TPY)
Total HAPs 0.07

PUBLIC NOTICE STATEMENT

The NOI for the above-referenced project has been evaluated and has been found to be consistent with the requirements of UAC R307. Air pollution producing sources and/or their air control facilities may not be constructed, installed, established, or modified prior to the issuance of an AO by the Director. A 30-day public comment period will be held in accordance with UAC R307-401-7. A notification of the intent to approve will be published in The Herald Journal on November 30, 2024. During the public comment period the proposal and the evaluation of its impact on air quality will be available for the public to review and provide comment. If anyone so requests a public hearing within 15 days of publication, it will be held in accordance with UAC R307-401-7. The hearing will be held as close as practicable to the location of the source. Any comments received during the public comment period and the hearing will be evaluated. The proposed conditions of the AO may be changed as a result of the comments received.
DAQE-IN162310001-24
Page 5

SECTION I: GENERAL PROVISIONS

The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the AO.

I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101] I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]
I.3 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1] I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the two-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of two (2) years. [R307-401-8]
I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO, including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4] I.6 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107]
I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150] I.8 The owner/operator shall submit documentation of the status of construction or modification to the Director within 18 months from the date of this AO. This AO may become invalid if construction is not commenced within 18 months from the date of this AO or if construction is discontinued for 18 months or more. To ensure proper credit when notifying the Director, send the documentation to the Director, attn.: NSR Section. [R307-401-18]

DAQE-IN162310001-24
Page 6

SECTION II: PERMITTED EQUIPMENT

The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the AO.
II.A THE APPROVED EQUIPMENT II.A.1 Hyrum RNG Facility
II.A.2 One (1) Anaerobic Digestor II.A.3 Two (2) H2S Vacuum Adsorption Vessels Arranged in series for operational flexibility
II.A.4 One (1) Molecular Gate (Molegate) PSA Skid Pressure Swing Adsorption II.A.5 One (1) Flare Burner Rating: 40 MMBtu/hr Maximum Inlet Heat Rating: 35.0 MMBtu/hr Burner Fuel: Natural Gas Minimum H2S Destruction Efficiency: 98%

SECTION II: SPECIAL PROVISIONS

The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the AO. II.B REQUIREMENTS AND LIMITATIONS II.B.1 Site-wide Requirements
II.B.1.a Unless otherwise specified in this AO, the owner/operator shall not allow visible emissions from any source on site to exceed 10% opacity. [R307-401-8] II.B.1.a.1 Unless otherwise specified in this AO, opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9. [R307-401-8]
II.B.1.b Unless otherwise specified in this AO, the following terms apply to the operations at the Hyrum RNG Facility: "Normal operations" means that the raw gas from the anaerobic digestor is treated by an H2S VAV and Molecular Gate PSA skid prior to entering the pipeline. All waste/tail gas from the PSA skid is routed to the flare stack and may or may not be combusted. "Emergency and/or maintenance operations" means periods of breakdown or maintenance of the VAVs or PSA skid, or periods of over-production of the anerobic digestor, where the raw gas from the anaerobic digestor may not be treated by the H2S VAV and/or Molecular Gate PSA skid prior to entering the pipeline. [R307-401-8]
DAQE-IN162310001-24
Page 7

II.B.1.c The owner/operator shall not produce more than 171.2 million standard cubic feet (MMscf) of waste (tail) gas per rolling 12-month period during normal operations. [R307-401-8] II.B.1.c.1 The owner/operator shall:
A. Determine production with flow meters B. Record production on a daily basis
C. Use the production data to calculate a new rolling 12-month total by the 20th day of each month using data from the previous 12 months
D. Keep the production records for all periods the plant is in operation.
[R307-401-8]
II.B.1.d The owner/operator shall not operate the Hyrum RNG Facility during emergency and/or maintenance operations. [R307-401-8] II.B.2 H2S VAV Requirements
II.B.2.a During normal operations, the owner/operator shall route all raw gas streams from the anaerobic digestor through an H2S VAV prior to entering the Molegate PSA skid. [R307-401-8] II.B.2.b The owner/operator shall install two (2) H2S VAVs that are each certified to meet a H2S emission
concentration of 50 ppm or less. [R307-401-8]

II.B.2.b.1 To demonstrate compliance with the above condition, the owner/operator shall maintain records of the manufacturer's emissions guarantee for the installed H2S VAVs. [R307-401-8]
II.B.3 Flare Requirements
II.B.3.a The owner/operator shall install a flare that is certified to meet a VOC and H2S destruction efficiency of no less than 98%, each. [R307-401-8]
II.B.3.a.1 To demonstrate compliance with the above condition, the owner/operator shall maintain records of the manufacturer's emissions guarantee for the installed flare. [R307-401-8]

II.B.3.b The owner/operator shall operate the flare according to the manufacturer's recommendations. [R307-401-8]
II.B.3.c The flare shall be equipped with an auto igniter. [R307-401-8]

II.B.3.c.1 The owner or operator shall maintain records demonstrating the date of installation and manufacturer specifications for the auto-igniter required under R307-503-4. [R307-503-4]
II.B.3.d The flare shall operate with no visible emissions. [R307-401-8]

II.B.3.d.1 Opacity observations of emissions from the flare shall be conducted according to 40 CFR 60, Appendix A, Method 22. [R307-401-8]

DAQE-IN162310001-24
Page 8

PERMIT HISTORY

This Approval Order shall supersede (if a modification) or will be based on the following documents: Is Derived From NOI dated August 14, 2024 Incorporates Additional Information dated August 28, 2024 Incorporates Additional Information dated October 3, 2024 Incorporates DAQE-MN162310001-24 dated October 9, 2024 Incorporates Additional Information dated October 15, 2024

DAQE-IN162310001-24
Page 9

ACRONYMS

The following lists commonly used acronyms and associated translations as they apply to this document:

40 CFR Title 40 of the Code of Federal Regulations
AO Approval Order
BACT Best Available Control Technology
CAA Clean Air Act
CAAA Clean Air Act Amendments
CDS Classification Data System (used by Environmental Protection Agency to classify
sources by size/type)
CEM Continuous emissions monitor
CEMS Continuous emissions monitoring system
CFR Code of Federal Regulations
CMS Continuous monitoring system
CO Carbon monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent - Title 40 of the Code of Federal Regulations Part 98,
Subpart A, Table A-1
COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality
DAQE This is a document tracking code for internal Division of Air Quality use
EPA Environmental Protection Agency
FDCP Fugitive dust control plan
GHG Greenhouse Gas(es) - Title 40 of the Code of Federal Regulations 52.21 (b)(49)(i)
GWP Global Warming Potential - Title 40 of the Code of Federal Regulations Part 86.1818-
12(a)
HAP or HAPs Hazardous air pollutant(s)
ITA Intent to Approve
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent
NOx Oxides of nitrogen
NSPS New Source Performance Standard
NSR New Source Review
PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size
PSD Prevention of Significant Deterioration
PTE Potential to Emit
R307 Rules Series 307
R307-401 Rules Series 307 - Section 401
SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act
Title V Title V of the Clean Air Act
TPY Tons per year
UAC Utah Administrative Code
VOC Volatile organic compounds

NOTICE
A Notice of Intent for the following project submitted in accor-dance with R307-401-1, Utah Administrative Code (UAC), has been received for consideration by the Director:
Company Name: GGUSA Hyrum LLCLocation: GGUSA Hyrum LLC - Renewable Natural Gas Facil-ity – 410 North 200 West, Hyrum, UTProject Description: GGUSA Hyrum LLC (GGUSA) has re-quested to construct a Renewable Natural Gas (RNG) Facility which will treat the biogas (raw gas) from anaerobic digestors and deliver the treated gas to a natural gas pipeline distribu-tion system in Hyrum, Cache County. The feed stream for the digestor will be waste from the adjacent Swift Beef Company, Incorporated (Swift Beef) beef processing plant.
The raw gas from the anaerobic digestors will be sent to a Vacuum Adsorption Vessel (VAV), which houses iron substrate that is used to controls H2S content. The gas stream is then sent through a molecular gate (Molegate) pressure swing ad-sorption (PSA) skid to remove CO2, H2S, and H2O in a single step. Methane, N2, and O2 pass through the molecular gate as “product gas” and is injected into the pipeline. The removed contaminants (CO2, H2S, and H2O), known as PSA “tail gas” or “waste gas,” will either be sent to the flare stack for release to ambient air without combustion or combusted for odor control. The flare will utilize natural gas for a pilot flame and additional natural gas as enrichment gas to ensure combustion. During non-normal operating scenarios, such as emergency or main-tenance operations, the RNG plant will not operate.
The completed engineering evaluation and air quality impact analysis showed the proposed project meets the requirements of federal air quality regulations and the State air quality rules. The Director intends to issue an Approval Order pending a 30-day public comment period. The project proposal, estimate of the effect on local air quality and draft Approval Order are available for public inspection and comment at the Utah Divi-sion of Air Quality, 195 North 1950 West, Salt Lake City, UT 84116. Written comments received by the Division at this same address on or before December 30, 2024, will be considered in making the final decision on the approval/disapproval of the proposed project. Email comments will also be accepted at [e-mail]. If anyone so requests to the Director in writ-ing within 15 days of publication of this notice, a hearing will be held in accordance with R307-401-7, UAC.
Under Section 19-1-301.5, a person who wishes to challenge a Permit Order may only raise an issue or argument during an adjudicatory proceeding that was raised during the public com-ment period and was supported with sufficient information or documentation to enable the Director to fully consider the sub-stance and significance of the issue.Published: November 30th, 2024 (HJ6167-586124)

DAQE-NN162310001-24

November 27, 2024

The Herald Journal
Legal Advertising Dept
1068 W 130 S
Logan, UT 84321

RE: Legal Notice of Intent to Approve

This letter will confirm the authorization to publish the attached NOTICE in The Herald Journal on
November 30, 2024.

Please mail the invoice and affidavit of publication to the Utah State Department of Environmental
Quality, Division of Air Quality, P.O. Box 144820, Salt Lake City, Utah 84114-4820. If you have any
questions, contact Jeree Greenwood, who may be reached at [phone].

Sincerely,

{{$s }}

Jeree Greenwood
Office Technician

Enclosure

cc: Cache County
cc: Bear River Association of Governments

195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
State of Utah

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

DAQE-NN162310001-24
Page 2
NOTICE

A Notice of Intent for the following project submitted in accordance with R307-401-1, Utah
Administrative Code (UAC), has been received for consideration by the Director:

Company Name: GGUSA Hyrum LLC
Location: GGUSA Hyrum LLC - Renewable Natural Gas Facility – 410 North 200 West,
Hyrum, UT
Project Description: GGUSA Hyrum LLC (GGUSA) has requested to construct a Renewable Natural
Gas (RNG) Facility which will treat the biogas (raw gas) from anaerobic
digestors and deliver the treated gas to a natural gas pipeline distribution system
in Hyrum, Cache County. The feed stream for the digestor will be waste from the
adjacent Swift Beef Company, Incorporated (Swift Beef) beef processing plant.

The raw gas from the anaerobic digestors will be sent to a Vacuum Adsorption
Vessel (VAV), which houses iron substrate that is used to controls H2S content.
The gas stream is then sent through a molecular gate (Molegate) pressure swing
adsorption (PSA) skid to remove CO2, H2S, and H2O in a single step. Methane,
N2, and O2 pass through the molecular gate as "product gas" and is injected into
the pipeline. The removed contaminants (CO2, H2S, and H2O), known as PSA
"tail gas" or "waste gas," will either be sent to the flare stack for release to
ambient air without combustion or combusted for odor control. The flare will
utilize natural gas for a pilot flame and additional natural gas as enrichment gas
to ensure combustion. During non-normal operating scenarios, such as
emergency or maintenance operations, the RNG plant will not operate.

The completed engineering evaluation and air quality impact analysis showed the proposed project meets
the requirements of federal air quality regulations and the State air quality rules. The Director intends to
issue an Approval Order pending a 30-day public comment period. The project proposal, estimate of the
effect on local air quality and draft Approval Order are available for public inspection and comment at the
Utah Division of Air Quality, 195 North 1950 West, Salt Lake City, UT 84116. Written comments
received by the Division at this same address on or before December 30, 2024, will be considered in
making the final decision on the approval/disapproval of the proposed project. Email comments will also
be accepted at [e-mail]. If anyone so requests to the Director in writing within 15 days of
publication of this notice, a hearing will be held in accordance with R307-401-7, UAC.

Under Section 19-1-301.5, a person who wishes to challenge a Permit Order may only raise an issue or
argument during an adjudicatory proceeding that was raised during the public comment period and was
supported with sufficient information or documentation to enable the Director to fully consider the
substance and significance of the issue.

Date of Notice: November 30, 2024

{{#s=Sig_es_:signer1:signature}}

OF7THE
Departmentof
Environmental Quality
Kimberly D.Shelley
Executive Director
DIVISION OF AIR QUALITY
Bryce C.Bird
Director
State of Utah
SPENCER J.COX
Govermor
DEIDRE HENDERSON
Lieutenant Govermor
RN162310001
November 21,2024
Casey Murakami
GGUSA Hyrum LLC
4287 Spruill Avenuc,Suite 202
North Charleston,SC 29405
[e-mail]
Dear Casey Murakami,
Engineer Review:
New Hyrum Renewable Natural Gas (RNG)Facility
Project Number:Nl623 10001
Re:
The DAQ rcquests a company representative review and sign the attached Engincer Review (ER).This
ER identifies all applicable clements of the New Source Revicw permitting program.GGUSA Hyrum
LLC should complete this review within 10 busines days of receipt.
GGUSA Hyrum LLC should contact Christine Bodell at(385))290-2690 if there are questions or
concerns with the review of the draft permit conditions.Upon resolution of your concerns,please email
Christine Bodell at [e-mail] the signed cover letter.Upon receipt of the signed cover letter,
the DAQ will prepare an ITA for a 30-day public comment period.At the completion of the comment
period,the DAQ will address any comments and will prepare an Approval Order (A0)for signature by
the DAQ Director.
If GGUSA Hyrum LLC does not respond to this letter within 10 business days,the project will move
forward without sourceconcurrence.If GGUSA HyrTum LLC hasconcerns that cannot be resolved and
the project becomes stagnant,the DAQ Director may issue an Order prohibiting construction.
Approval Signature Nov.21,2024
(Signature &Date)
195 North 1950 West Salt Lake City.UT
Mailing Address:P.O.Box 144820 •'Salt Lake City,UT 84114-4820
Telephone (801)$36-4000 •Fax [phone] •TD.D.[phone]
www.deg.utah.gov
Printed on 100%recycled paper
DAQE-

RN162310001 November 21, 2024 Casey Murakami
GGUSA Hyrum LLC 4287 Spruill Avenue, Suite 202 North Charleston, SC 29405
[e-mail] Dear Casey Murakami,
Re: Engineer Review: New Hyrum Renewable Natural Gas (RNG) Facility Project Number: N162310001 The DAQ requests a company representative review and sign the attached Engineer Review (ER). This ER identifies all applicable elements of the New Source Review permitting program. GGUSA Hyrum LLC should complete this review within 10 business days of receipt. GGUSA Hyrum LLC should contact Christine Bodell at [phone] if there are questions or concerns with the review of the draft permit conditions. Upon resolution of your concerns, please email Christine Bodell at [e-mail] the signed cover letter. Upon receipt of the signed cover letter, the DAQ will prepare an ITA for a 30-day public comment period. At the completion of the comment period, the DAQ will address any comments and will prepare an Approval Order (AO) for signature by the DAQ Director. If GGUSA Hyrum LLC does not respond to this letter within 10 business days, the project will move
forward without source concurrence. If GGUSA Hyrum LLC has concerns that cannot be resolved and the project becomes stagnant, the DAQ Director may issue an Order prohibiting construction. Approval Signature _____________________________________________________________ (Signature & Date)
195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
State of Utah
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 1
UTAH DIVISION OF AIR QUALITY
ENGINEER REVIEW

SOURCE INFORMATION
Project Number N162310001 Owner Name GGUSA Hyrum LLC Mailing Address 4287 Spruill Avenue, Suite 202
North Charleston, SC, 29405 Source Name GGUSA Hyrum LLC - Renewable Natural Gas Facility
Source Location 410 North 200 West Hyrum, UT 84319
UTM Projection 428,370 m Easting, 4,610,901 m Northing UTM Datum NAD83 UTM Zone UTM Zone 12 SIC Code 1311 (Crude Petroleum & Natural Gas) Source Contact Casey Murakami Phone Number [phone] Email [e-mail] Billing Contact Casey Murakami Phone Number [phone]
Email [e-mail] Project Engineer Christine Bodell, Engineer
Phone Number [phone] Email [e-mail]
Notice of Intent (NOI) Submitted August 14, 2024 Date of Accepted Application September 9, 2024

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 2
SOURCE DESCRIPTION General Description
GGUSA Hyrum LLC (GGUSA) has requested to construct a Renewable Natural Gas (RNG) Facility which will treat the biogas (raw gas) from anaerobic digestors and deliver the treated gas to a natural gas pipeline distribution system in Hyrum, Cache County. The feed stream for the
digestor will be waste from the adjacent Swift Beef Company, Incorporated (Swift Beef) beef processing plant. The raw gas from the anaerobic digestors will be sent to a Vacuum Adsorption Vessel (VAV), which houses iron substrate that is used to controls H2S content. The gas stream is then sent through a molecular gate (Molegate) pressure swing adsorption (PSA) skid to remove CO2, H2S, and H2O in a single step. Methane, N2 and O2 pass through the molecular gate as "product gas" and is injected into the pipeline. The removed contaminants (CO2, H2S, and H2O), known as PSA "tail gas" or "waste gas", will either be sent to the flare stack for release to ambient air without combustion or combusted for odor control. The flare will utilize natural gas for a pilot flame and additional natural gas as enrichment gas to ensure combustion.
NSR Classification: New Minor Source
Source Classification Located in Attainment Area
Cache County Airs Source Size: B Applicable Federal Standards None
Project Proposal New Hyrum Renewable Natural Gas (RNG) Facility Project Description GGUSA Hyrum LLC (GGUSA) has requested to construct a Renewable Natural Gas (RNG) Facility which will treat the biogas (raw gas) from anaerobic digestors and deliver the treated gas to a natural gas pipeline distribution system in Hyrum, Cache County. The feed stream for the anaerobic digestor will be waste from the adjacent Swift Beef Company, Incorporated (Swift
Beef) beef processing plant. Under normal operations, the raw gas from the digestor is treated with an H2S VAV and a PSA
skid. The H2S VAV will reduce H2S in the gas stream to no more than 50 ppm, and the PSA skid will filter out the remaining H2S, as well as CO2 and H2O. The H2 S, CO2, and H2O waste stream
is then directed to the flare stack, where it may or may not be combusted. The flare is utilized as a
control device for odor control. During non-normal operating scenarios, such as emergency or maintenance operations, the RNG plant will not operate. EMISSION IMPACT ANALYSIS The new criteria and HAPs emissions did not trigger the requirement for GGUSA to conduct modeling for criteria pollutants or HAPs under Utah Administrative Code (UAC) R307-410-4 and R307-410-5.

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 3
The UDAQ conducted 1-hour NOx and 1-hour SO2 modeling analyses. The results indicated that the highest 1-hour NOx and 1-hour SO2 impacts would be 88.6% and 75.4% of NAAQS levels, respectively.
The UDAQ conducted 24-hour hydrogen sulfide (H2S) modeling analyses. The results indicated that the highest 24-hour H2S impact would be 14.8% of the Toxic Screening Level (TSL).
See modeling memorandum DAQE-MN162310001-24, dated October 9, 2024 for more information.
[Last updated October 16, 2024]

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 4
SUMMARY OF EMISSIONS
The emissions listed below are an estimate of the total potential emissions from the source. Some rounding of emissions is possible.
Criteria Pollutant Change (TPY) Total (TPY) CO2 Equivalent 15961.00 Carbon Monoxide 12.15
Nitrogen Oxides 5.41
Particulate Matter - PM10 0.29
Particulate Matter - PM2.5 0.29
Sulfur Dioxide 1.76
Volatile Organic Compounds 25.87 Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Generic HAPs (CAS #GHAPS) 140
Change (TPY) Total (TPY)
Total HAPs 0.07

Note: Change in emissions indicates the difference between previous AO and proposed modification.

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 5
Review of BACT for New/Modified Emission Units 1. BACT review regarding H2S Emissions
Under normal operations, when the gas is treated by the VAV and PSA and not combusted, there are no criteria or HAPs pollutants emitted from the facility. However, GGUSA has elected to operate a flare as a control technology for odor control during normal operating scenarios.
When untreated, the tail gas from the PSA skid can contain up to 4,270 ppm of H2S. When combusted, H2S is converted to SO2. A maximum daily potential throughput of 19,543 scf/hr of tail gas flow through the flare results in an uncontrolled PTE of 52.21 tpy of SO2. Therefore, a BACT analysis was conducted to reduce SO2 emissions from the flare.
Technologies to reduce SO2 emissions include use of a wet caustic scrubber, fixed-bed activated carbon, iron removal methods, biological methods, and flare/thermal oxidation. Each technology aims to reduce H2S in the inlet stream, therefore reducing SO2 emissions in the flare exhaust
stream. A caustic scrubber is a device in which tail gas flows countercurrent to a solution of sodium hydroxide (caustic) and water. H2S is highly soluble in water and when dissolved results in an
acidic solution. The dissolved H2S readily reacts with the caustic solution to form sodium sulfite and sodium hydrosulfite which precipitate out of the solution. Due to the insoluble nature of these precipitates, the caustic solution is not regenerative and often requires offsite disposal or sale. Since this process uses a solvent which cannot be easily regenerated, caustic scrubbers are most often applied in situations where small volumes of H2S need to be removed, typically referred to as scavenging when combined with other control technologies. This system is generally used for systems with a sulfur production capacity between 0.1 and 10 tons per day. The maximum untreated emission rate of H2S is anticipated to be less than 0.1 tons per day; therefore, this technology is infeasible.
The most common dry technique is to install a packed bed scrubber containing activated carbon.
This control method has been used to effectively treat H2S at landfills and wastewater treatment plants. Activated carbon is a form of carbon that has been processed to make it extremely porous to increase the surface area available for adsorption or other chemical reactions. Activated carbon can be impregnated with alkaline or oxide solids to improve adsorption of H2S. Common applications include sodium hydroxide, sodium carbonate, potassium hydroxide, potassium iodide, and metal oxides. Typically, 20 - 25% loading by weight of H2S can be achieved.
Upon saturation of the activated carbon, the spent media must be replaced with fresh material.
While spent activated carbon can be thermally regenerated using the same process in which it was made, it is typically more economically favorable to simply purchase new activated carbon from a supplier. The continual replacement of spent media results in a significant solid waste stream
which lacks an environmentally friendly disposal method. Additionally, this replacement results in relatively high labor costs due to materials handling/disposal. Due to the large amounts of waste anticipated and low control efficiency, activated carbon scrubbing is considered technically impracticable and not further considered as BACT. [Last updated October 16, 2024] 2. BACT review regarding H2S Emissions Continued Iron Removal Methods: Iron can be added in a variety of methods to reduce H2S in a fuel or tail
gas stream. Iron has the ability to readily donate electrons to a reaction, making it an excellent reducing agent or catalyst for other sulfur reactions. Upon a review of available iron removal

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 6
methods, GGUSA determined that Vacuum Adsorption Vessel (VAV) technology was most compatible with the process. This technology involves both an iron media that extracts the H2S and
a vessel specially crafted to house the media. The vessel is specifically designed for digestors and similar processes to facilitate even gas flow through the media bed with low pressure restriction. The media used is an iron-oxide-hydroxide (FeO(OH)), which undergoes two distinct reactions when it encounters hydrogen sulfide. A secondary reaction then occurs, under proper moisture and
oxygen conditions, which naturally regenerates the catalyst. The sulfur precipitates out as a powdery coating and can be easily disposed of. This regeneration reaction does not occur indefinitely but does prolong the media life significantly. In conversations with the vendor, it is anticipated that the sulfur content can be lowered to 50 ppmv, which represents a 96-99% control efficiency. Use of a VAV containing iron-oxide-hydroxide is considered technically feasible. Biological Methods: There are a variety of biological agents that process H2S and reduce the potential for air emissions. These methods have been implemented as a method for reducing the sulfur content of the raw biogas prior to further treatment. Sulfur-oxidizing bacteria and a small amount of oxygen are commonly inserted into a digester to breakdown the H2S produced through fermentation. In this process, bacteria that convert H2S to elemental sulfur grow on digester walls
and surfaces above the liquid surface, on the liquid surface, or on a biological filter medium. Research and experience indicate that the start-up period for a biological treatment system can be anywhere from a few days to a month. This slow start-up time is a result of the culture needing time to develop and for the microorganisms to multiply to a level sufficient for the treatment of the desired pollutant. As a result, this technology is considered technically impracticable and is not further considered.
Flare/Thermal Oxidation: Properly designed flares/thermal oxidization systems can be expected
to achieve 98% control of H2S emissions. The thermal oxidizer or flare would require a natural gas burner which produces secondary criteria pollutants and produces high SO2 emissions from the conversion of H2S. Furthermore, the tail gas stream contains very little methane which results in a
very low BTU value. To ensure proper combustion, enrichment gas would be required. This technology is considered technically feasible. BACT is the utilization of VAV technology (96-99% H2S reduction) during all normal operations. Should H2S emissions or other odor causing compounds be detected in the surrounding
community, a flare (98% H2S reduction) is to be used as a control in series with the VAV. Under emergency and maintenance conditions, such as over production of the digestor or breakdown of the VAV, the RNG Facility will not operate. This is considered BACT.
[Last updated October 16, 2024] 3. BACT review regarding Component Fugitive Emissions
During the processing of renewable natural gas, minimal emissions from component leaks are anticipated. VOC emissions associated with equipment leaks are estimated at 0.04 tpy. As such, no further BACT analysis has been completed, as emissions are minimal and additional controls would not be economically feasible. [Last updated August 27, 2024]
SECTION I: GENERAL PROVISIONS

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 7
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as “New” in the Outline Label): I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions
refer to those rules. [R307-101] I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401] I.3 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1]
I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the two-year period prior to the date of the request.
Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of two (2) years. [R307-401-8]
I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO, including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable
operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.
All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4]
I.6 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107] I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]
I.8 The owner/operator shall submit documentation of the status of construction or modification
to the Director within 18 months from the date of this AO. This AO may become invalid if construction is not commenced within 18 months from the date of this AO or if construction is discontinued for 18 months or more. To ensure proper credit when notifying the Director, send the documentation to the Director, attn.: NSR Section. [R307-401-18]

SECTION II: PERMITTED EQUIPMENT
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.A THE APPROVED EQUIPMENT

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 8
II.A.1 NEW Hyrum RNG Facility II.A.2 NEW One (1) Anaerobic Digestor II.A.3 NEW Two (2) H2S Vacuum Adsorption Vessels (VAVs) Arranged in series for operationally flexibility

II.A.4 NEW One (1) Molecular Gate (Molegate) PSA Skid Pressure Swing Adsorption
II.A.5 NEW One (1) Flare Burner Rating: 40 MMBtu/hr
Maximum Inlet Heat Rating: 35.0 MMBtu/hr Burner Fuel: Natural Gas Minimum H2S Destruction Efficiency: 98%

SECTION II: SPECIAL PROVISIONS
The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.B REQUIREMENTS AND LIMITATIONS II.B.1 NEW Site-wide Requirements
II.B.1.a NEW Unless otherwise specified in this AO, the owner/operator shall not allow visible emissions from any source on site to exceed 10% opacity. [R307-401-8]
II.B.1.a.1 NEW Unless otherwise specified in this AO, opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9. [R307-401-8]
II.B.1.b NEW Unless otherwise specified in this AO, the following terms apply to the operations at the Hyrum RNG Facility:
"Normal operations" means that the raw gas from the anaerobic digestor is treated by an H2S
Vacuum Adsorption Vessel (VAV) and Molecular Gate Pressure Swing Adsorption (PSA) skid prior to entering the pipeline. All waste/tail gas from the PSA skid is routed to the flare stack and may or may not be combusted.
"Emergency and/or maintenance operations" means periods of breakdown or maintenance of
the VAVs or PSA skid, or periods of over-production of the anerobic digestor, where the raw gas from the anaerobic digestor may not be treated by the H2S VAV and/or Molecular Gate PSA skid prior to entering the pipeline.
[R307-401-8]

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 9
II.B.1.c NEW The owner/operator shall not produce more than 171.2 million standard cubic feet (MMscf) of waste (tail) gas per rolling 12-month period during normal operations. [R307-401-8]
II.B.1.c.1 NEW The owner/operator shall: A. Determine production with flow meters B. Record production on a daily basis C. Use the production data to calculate a new rolling 12-month total by the 20th
day of each month using data from the previous 12 months D. Keep the production records for all periods the plant is in operation. [R307-401-8] II.B.1.d NEW The owner/operator shall not operate the Hyrum RNG Facility during emergency and/or maintenance operations. [R307-401-8]
II.B.2 NEW H2S Vacuum Adsorption Vessel (VAV) Requirements
II.B.2.a NEW During normal operations, the owner/operator shall route all raw gas streams from the anaerobic digestor through an H2S VAV prior to entering the Molegate PSA skid. [R307-401-8]

II.B.2.b NEW The owner/operator shall install two (2) H2S VAVs that are each certified to meet a hydrogen sulfide (H2S) emission concentration of 50 ppm or less. [R307-401-8]
II.B.2.b.1 NEW To demonstrate compliance with the above condition, the owner/operator shall maintain records of the manufacturer's emissions guarantee for the installed H2S VAVs. [R307-401-8]
II.B.3 NEW Flare Requirements
II.B.3.a NEW The owner/operator shall install a flare that is certified to meet a VOC and H2S destruction efficiency of no less than 98%, each. [R307-401-8]

II.B.3.a.1 NEW To demonstrate compliance with the above condition, the owner/operator shall maintain records of the manufacturer's emissions guarantee for the installed flare. [R307-401-8] II.B.3.b NEW The owner/operator shall operate the flare according to the manufacturer's recommendations. [R307-401-8]

II.B.3.c NEW The flare shall be equipped with an auto-igniter. [R307-401-8] II.B.3.c.1 NEW The owner or operator shall maintain records demonstrating the date of installation and manufacturer specifications for the auto-igniter required under R307-503-4. [R307-503-4]
II.B.3.d
NEW
The flare shall operate with no visible emissions. [R307-401-8]

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 10
II.B.3.d.1 NEW Opacity observations of emissions from the flare shall be conducted according to 40 CFR 60, Appendix A, Method 22. [R307-401-8]

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 11
PERMIT HISTORY When issued, the approval order shall supersede (if a modification) or will be based on the
following documents: Is Derived From NOI dated August 14, 2024
Incorporates Additional Information dated August 28, 2024 Incorporates Additional Information dated October 3, 2024 Incorporates Modeling Memo DAQE-MN162310001-24 dated October 9, 2024 Incorporates Additional Information dated October 15, 2024
REVIEWER COMMENTS
1. Comment regarding Source Emission Calculations and DAQ Acceptance: Normal operating conditions are based on 19,543 scf/hr, or 171,196,680 scf/year (171.2 MMscf/yr) of waste/tail gas flow, considering normal operations are expected to take place 8,760 hours annually. During normal operations, the raw gas is treated by the VAV and PSA skid. The VAV skid is certified to reduce H2S in the raw gas stream to 50 ppm. The gas stream then enters the PSA skid, where the flow is separated between product gas and waste/tail gas.
The concentration of H2S leaving the PSA skid is increased to 142 ppm in the tail/waste gas stream
due to the decrease in overall flow as the product gas is removed from the gas stream. The product gas is sent to the pipeline and the tail/waste gas is sent to the flare stack, where it may or may not be combusted. The flare has a guaranteed destruction efficiency of 98% of H2S. The destructed H2S is
converted to SO2, while the remaining 2% is emitted as H2S. For a conservative emissions estimate, the emissions from both operating scenarios (combustion versus no combustion), assuming 8,760 hours of annual operation for each scenario, were summed to calculate the site-wide PTE.
Flare Emissions The flare includes a natural gas-fired burner rated at 40 MMBtu/hr. Emissions due to flare combustion were calculated using the following:
NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021). CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2 CO2e Emission Factors from 40 CFR 98 Tables C-1 and C-2 and 40 CFR 98 Table A-1. HAPs Emission Factors from AP-42 Section 1.4 Table 1.4-3 [Last updated October 10, 2024] 2. Comment regarding Federal Standard/Title V Applicability: Title V of the 1990 CAA (Title V) applies to the following: A. Any major source B. Any source subject to a standard, limitation, or other requirement under Section 111 of the Act, Standards of Performance for New Stationary Sources
C. Any source subject to a standard or other requirement under Section 112 of the Act, Hazardous Air Pollutants

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 12
D. Any Title IV-affected source This facility is not a major source and is not a Title IV source. The facility is not subject to any 40 CFR 60 (NSPS), 40 CFR 61 (NESHAP), or 40 CFR 63 (MACT) regulations. Therefore, Title V does not apply to this facility. [Last updated September 4, 2024]
3. Comment regarding Name Change Request: "GreenGas USA" initially submitted the NOI and is therefore referenced in modeling memorandum DAQE-MN162310001-24. During the DAQ NOI review period. GreenGas USA requested a name change to "GGUSA Hyrum LLC". The new name and mailing address were updated accordingly. All other aspects (primary contact, site name, etc.) are to remain the same. [Last updated November 13, 2024]

Engineer Review N162310001: GGUSA Hyrum LLC - Renewable Natural Gas Facility November 21, 2024 Page 13
ACRONYMS The following lists commonly used acronyms and associated translations as they apply to this document:
40 CFR Title 40 of the Code of Federal Regulations AO Approval Order BACT Best Available Control Technology
CAA Clean Air Act CAAA Clean Air Act Amendments CDS Classification Data System (used by EPA to classify sources by size/type) CEM Continuous emissions monitor CEMS Continuous emissions monitoring system CFR Code of Federal Regulations CMS Continuous monitoring system CO Carbon monoxide CO2 Carbon Dioxide CO2e Carbon Dioxide Equivalent - 40 CFR Part 98, Subpart A, Table A-1 COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality DAQE This is a document tracking code for internal UDAQ use EPA Environmental Protection Agency
FDCP Fugitive dust control plan GHG Greenhouse Gas(es) - 40 CFR 52.21 (b)(49)(i) GWP Global Warming Potential - 40 CFR Part 86.1818-12(a)
HAP or HAPs Hazardous air pollutant(s) ITA Intent to Approve LB/HR Pounds per hour
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units
NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent NOx Oxides of nitrogen NSPS New Source Performance Standard NSR New Source Review PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size PSD Prevention of Significant Deterioration PTE Potential to Emit
R307 Rules Series 307 R307-401 Rules Series 307 - Section 401 SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act Title V Title V of the Clean Air Act TPY Tons per year
UAC Utah Administrative Code VOC Volatile organic compounds

DAQE-MN162310001-24

M E M O R A N D U M

TO: Christine Bodell, NSR Engineer

FROM: Jason Krebs, Air Quality Modeler

DATE: October 9, 2024

SUBJECT: Modeling Analysis Review for the Notice of Intent for GreenGasUSA – Renewable
Natural Gas Facility, Cache County, Utah
_____________________________________________________________________________________
This is not a Major Prevention of Significant Deterioration (PSD) Source.
I. OBJECTIVE
GreenGasUSA (Applicant) is seeking an approval order for their renewable natural gas facility
located in Cache County, Utah. The Applicant has requested to construct a Renewable Natural Gas
(RNG) Facility which will treat the biogas (raw gas) from anaerobic digestors and deliver the
treated gas to a natural gas pipeline distribution system in Hyrum, Cache County. The feed stream
for the anaerobic digestor will be waste from the adjacent Swift Beef Company, Incorporated
(Swift Beef) beef processing plant.
Under normal operations, the raw gas from the digestor is treated with an H2S VAV and a PSA
skid. The H2S VAV will reduce H2S in the gas stream to no more than 50 ppm, and the PSA skid
will filter out the remaining H2S, as well as CO2 and H2O. The H2s, CO2, and H2O waste stream
is then directed to the flare stack, where it may or may not be combusted. When the waste stream is
not combusted (normal operations), no criteria pollutants or HAPs are emitted from the facility. The
flare is utilized during emergencies or maintenance operations, and results in combustion air
pollutants such as NOx, CO, VOCs, particulate matter, and HAPs.

This report, prepared by the Staff of the New Source Review Section (NSR), contains a review of
the air quality impact analysis (AQIA) including the information, data, assumptions and modeling
results used to determine if the facility will be in compliance with applicable State and Federal
concentration standards.

II. APPLICABLE RULE(S)
Utah Air Quality Rules:
R307-401-6 Condition for Issuing an Approval Order R307-410-3 Use of Dispersion Models
R307-410-4 Modeling of Criteria Pollutants in Attainment Areas

195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
State of Utah

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

JK
DAQE- MN162310001-24
Page 2
R307-410-5 Documentation of Ambient Air Impacts for Hazardous Air Pollutants
III. MODELING METHODOLOGY
A. Applicability

Emissions from the facility include PM10, NOx, CO, SO2, and HAPs. This modeling is part of a
new approval order. The emission rates for Hydrogen Sulfide (H2S), NOx and SO2 trigger the requirement to model under R307-410. HAP modeling was performed by the Applicant. NO2 and SO2 modeling was performed by the UDAQ.

B. Assumptions

1. Topography/Terrain

The Plant is at an elevation 4628 feet with terrain features that have an affect on
concentration predictions.

a. Zone: 12

b. Approximate Location:
UTM (NAD83): 428248 meters East 4610573 meters North
2. Urban or Rural Area Designation
After a review of the appropriate 7.5 minute quadrangles, it was concluded the area is
“rural” for air modeling purposes.
3. Ambient Air
It was determined the Plant boundary used in the AQIA meets the State’s definition of ambient air.
4. Building Downwash

The source was modeled with the AERMOD model. All structures at the plant were used in
the model to account for their influence on downwash.
5. Meteorology

Five (5) years of off-site surface and upper air data were used in the analysis consisting of the following:

Surface – Logan Airport, UT NWS: 2018-2022
Upper Air – Salt Lake Airport, UT NWS: 2018-2022

6. Background

No background concentrations were added to the results.

DAQE- MN162310001-24
Page 3
7. Receptor and Terrain Elevations

The modeling domain used by the Applicant consisted of receptors including property
boundary receptors. This area of the state contains mountainous terrain and the modeling
domain has simple and complex terrain features in the near and far fields. Therefore,
receptor points representing actual terrain elevations from the area were used in the
analysis.
8. Model and Options
The State-accepted AERMOD model was used to predict air pollutant concentrations under
a simple/complex terrain/wake effect situation. In quantifying concentrations, the regulatory default option was selected.
9. Air Pollutant Emission Rates
GreenGasUSA
Source
UTM Coordinates Modeled Emission Rates
Easting Northing H2S
(m) (m) (lb/hr) (tons/yr) hrs/year
FLARE 428346 4610917 0.22 0.96 8760

Total 0.22 0.96
GreenGasUSA
Source
UTM Coordinates Modeled Emission Rates
Easting Northing NOx
(m) (m) (lb/hr) (tons/yr) hrs/year
FLARE 428346 4610917 6.01 26.32 8760

Total 6.01 26.32
Swift Beef
Source
UTM Coordinates Modeled Emission Rates
Easting Northing NOx
(m) (m) (lb/hr) (tons/yr) hrs/year
BEEF 428402 4610505 14.95 65.50 8760
Total 14.95 65.50

DAQE- MN162310001-24
Page 4

Kilgore Hyrum Pit
Source
UTM Coordinates Modeled Emission Rates
Easting Northing NOx
(m) (m) (lb/hr) (tons/yr) hrs/year
AS_HOH 431208 4610201 2.43 10.64 8760
AS_BAGH 431209 4610196 2.43 10.64 8760
CP_BOIL 431113 4610157 2.43 10.64 8760
Total 7.29 31.93 GreenGasUSA
Source
UTM Coordinates Modeled Emission Rates
Easting Northing SO2
(m) (m) (lb/hr) (tons/yr) hrs/year
FLARE 428346 4610917 0.40 1.75 8760

Total 0.40 1.75
Swift Beef
Source
UTM Coordinates Modeled Emission Rates
Easting Northing SO2
(m) (m) (lb/hr) (tons/yr) hrs/year
BEEF 428402 4610505 8.90 38.98 8760

Total 8.90 38.98
10. Source Location and Parameters
Source Type
Source Parameters
Elev, Ht Temp Flow Dia
(ft) (m) (ft) (K) (m/s) (ft)
FLARE POINT 4586.0 6.1 20.0 422 6.78 0.15
BEEF POINT 4616.7 11.9 39.0 500 15.00 0.61
AS_HOH POINT 4767.9 6.6 21.5 422 15.24 0.39
AS_BAGH POINT 4768.1 2.4 8.0 589 4.66 0.30
CP_BOIL POINT 4771.9 16.5 54.0 505 4.66 0.30

DAQE- MN162310001-24
Page 5
IV. RESULTS AND CONCLUSIONS

A. National Ambient Air Quality Standards

The below table provides a comparison of the predicted total air quality concentrations with the
NAAQS. The predicted total concentrations are less than the NAAQS.

Air
Pollutant
Period Prediction Class II
Significant
Impact
Level
Background Nearby
Sources*
Total NAAQS Percent
(μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) NAAQS
NO2
1-
Hour 142.4 7.5 24.2 0.0 166.6 188 88.6%

Air
Pollutant
Period Prediction Class II
Significant
Impact
Level
Background Nearby
Sources*
Total NAAQS Percent
(μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3) NAAQS
SO2
1-
Hour 4.9 7.5 106.9 35.9 147.7 195 75.4%

B. Toxic Screening Levels

The model predicted all HAP concentrations to be less than their respective UDAQ - Toxic
Screening Levels (TSL) for each scenario. Based on these results, no further analysis is
required.

Pollutant Period
Prediction TSL Percent
(μg/m3) (μg/m3)
H2S 24-hr 6.8 46 14.8%
JK:jg

SCENARIO 1a SCENARIO 1b
Treated Tail Gas Emitted Treated Tail Gas Emitted
Digestors -> VAV -> PSA -> Flare (Not Combusted)Digestors -> VAV -> PSA ->
19543 scf/hr tail gas flow 98 % H2S effic
335 days/yr 365 days/yr
8040 hrs/year 8760 hrs/year
142 ppm H2S
19,543.00 scf/hr
142 ppm H2S
0.000142 ppm H2S concentration 0.000003 H2S ppm c
2.78 scf/hr H2s 0.06 scf/hr H2s
Rest gets converted to SO
0.21 lb/hr H2S 2.72 scf/hr SO2
0.86 tpy H2S
0.00 lb/hr
0.02 tpy
0.40 lb/hr
1.74 tpy
###########
VAV treats gas to contain a max of 50 ppm H2S Pilot Light
PSA removed CO2, H2S, and H20 from gas
Hs2 from PSA (treated) is 142 ppm 8774 scf/hr max
Untreated by VAV = 1500 ppm H2S 1020 Btu/scf NG
Flare H2S efficiency = 98%8.94948 MMBtu/hr
34 H2S lb/lbmol lb/MMBtu
64 SO2 lb/lbmol NOx 0.138
CO 0.31
VOCs 0.66
PM
SO2
HAPs
Fugitives Count EF (lb/hr/source)
Valves -Gas 30 0.0132
Flanges - Gas 60 0.0039
Com Seals- Gas 3 0.5
Relief Valves - Ga 15 0.229
Normal Operations
H2S wt%0.15
0.01 lb/hr H2S
0.04 tpy H2S
SCENARIO 2a
Treated Tail Gas Emitted
> Flare (Combusted)Digestors -> PSA -> Flare (Combusted)
ciency 98 % H2S efficiency
30 days/yr
720 hrs/year
19543 scf/hr tail gas flow
4270 ppm H2S
tail gas flow 0.00427 H2S concentration
83.45 scf/hr H2s
oncentration 0.000085 ppm H2S concentration controlled
1.67 scf/hr H2s
O2 Rest gets converted to SO2
81.78 scf/hr SO2
H2S 0.13 lb/hr H2S
H2S 0.05 tpy H2S
SO2 11.92 lb/hr SO2
SO2 4.29 tpy SO2
##########
Pilot Light
x NG flow 8774 scf/hr max NG flow
G heating value 1020 Btu/scf NG heating value
r 8.94948 MMBtu/hr
lb/MMscf lb/hr tpy lb/MMBtu lb/MMscf lb/hr tpy
1.24 5.41 NOx 0.138 1.24 0.44
2.77 12.15 CO 0.31 2.77 1.00
5.91 25.87 VOCs 0.66 5.91 2.13
7.6 0.07 0.29 PM 7.6 0.07 0.02
0.6 0.01 0.02 SO2 0.6 0.01 0.00
2 0.02 0.043 HAPs 2 0.02 0.0038

Pollutant

1a Scenario 1b

2a Scenario 2b Fug Total
NOX 5.41 0.44 1.72 7.13
CO 12.15 1.00 3.86 16.01
PM10 0.29 0.02 0.09 0.38
PM2.5 0.29 0.02 0.09 0.38
SO2 1.76 4.29 3.73 6.05
VOC 25.87 2.13 8.22 34.09
Emergy
H2S 0.86 0.02 0.05 0.04 0.04 0.91
HAP 0.00 0.04 0.00 0.02 0.07
***the highest PTE was chosen for the 1 and 2 scenarios
SCENARIO 2b
Treated Tail Gas Emitted
Digestors -> Flare (Combusted)
98 % H2S efficiency
30 days/yr
720 hrs/year
48302 scf/hr raw gas flow
1500 ppm H2S
0.0015 H2S concentration
72.45 scf/hr H2s
0.000030 ppm H2S concentration
1.44906 scf/hr H2s
Rest gets converted to SO2
71.00 scf/hr SO2
0.11 lb/hr H2S
0.04 tpy H2S
10.35 lb/hr SO2
3.73 tpy SO2
###########
Pilot Light
33912 scf/hr max NG flow
1020 Btu/scf NG heating value
34.59024 MMBtu/hr
lb/MMBtu lb/MMscf lb/hr tpy
NOx 0.138 4.77 1.72
CO 0.31 10.72 3.86
VOCs 0.66 22.83 8.22
PM 7.6 0.26 0.09
SO2 0.6 0.02 0.01
HAPs 1.894 0.06 0.02
*NOI values more accuate due to rounding.
y/Maintenance Operations
all values within tolerance

4525 Wasatch Blvd, Ste 200, Salt Lake City, UT 84124 P 801.272.3000 / F 801.272.3040
To: Christine Bodell, UDAQ
From: Henry Vossler, Trinity Consultants
Date: October 3, 2024
RE: GreenGasUSA Hyrum, UT Notice of Intent Application Revision
Dear Christine,
On August 14th, 2024, GreenGasUSA (GreenGas) submitted a Notice of Intent (NOI) air permit application
for a proposed renewable natural gas facility in Hyrum, Utah. The application outlined several operating
scenarios, as described below and illustrated in Figure 4-1 of the application:

► 1. Normal Operation Scenarios
• 1a. Tail gas is treated by the VAV and is emitted directly without flaring.
• 1b. Tail gas is treated by the VAV and is flared.
► 2. Emergency/Maintenance Operation Scenarios
• 2a. Tail gas is not treated by the VAV and is flared.
• 2b. Raw gas is not treated and is flared.

During the pre-application call, the Utah Division of Air Quality (UDAQ) referenced the state’s new significant
impact level (SIL) for SO2 modeling and informed GreenGas that modeling would be required for this
project. Because the modeling results pertaining to the "Emergency/Maintenance Operation Scenarios”
significantly exceeded the SIL limits and the necessary adjustments were not feasible, GreenGas has elected
to remove these scenarios (2a and 2b) from the permit application completely. In the event of an
emergency or planned maintenance scenario, the RNG plant will not operate.
Trinity Consultants, Inc. (Trinity) has updated the potential to emit (PTE) calculations of the proposed
facility. A revised version of the emission calculations is attached in Appendix A, replacing the emissions
calculations previously included in Appendix B of the submitted NOI air permit application.
Please review the updated emissions calculations at your earliest convenience. If you have any questions or
need further clarification, do not hesitate to contact us.
APPENDIX A – REVISED EMISSIONS CALCULATIONS

GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-1. GreenGasUSA Potential To Emit Annual Emissions Summary
NOX NO2 CO PM10 PM2.5 SO2 VOC CO2e H2S Total HAPs
1a Treated Tail Gas Emitted -------15518.67 0.94 0.001bTreated Tail Gas Combusted 5.41 5.41 12.15 0.29 0.29 1.76 25.87 7397.65 0.02 0.07-------442.57 0.04 0.00
5.41 5.41 12.15 0.29 0.29 1.76 25.87 15961.24 0.98 0.07
100 100 250 250 100 100 250 100,000 -10/25NoNoNoNoNoNoNoNo-No
40 40 100 15 10 40 ----See HAPS Summary See HAPS SummaryNoNoNoNoNoNoNoNoNoNo
1. Facility wide PTE is calculated by summing the maximum of scenarios 1a and 1b with the maximum of scenarios 2a and 2b, including fugitive emissions
2. Major source thresholds are defined by 40 CFR section 52.21(b)(1).
3. Modeling Limit is stated in UDAQ Emissions Impact Assessment Guidelines under Table 1: Total Controlled Emission Rates for New Sources or Emissions Increase.
Maximum Potential To Emit (tpy)
Major Source Thresholds2
Threshold Exceeded?
Modeling Limits3
Threshold Exceeded?
Scenario Description
Fugitives
Scenario Number
Facility Wide PTE1
Scenario
Normal (VAV operational)
GreenGasUSA 10/1/2024 Page 1 of 6
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-2. Average Potential HAP Emissions
Scenario 1a Scenario 1b
2-Methylnaphthalene -1.11E-07 1.11E-07 --No3-Methylcholanthrene -8.36E-09 8.36E-09 --No
7,12-Dimethylbenz(a)anthracene -7.43E-08 7.43E-08 --NoAcenaphthene-8.36E-09 8.36E-09 --No
Acenaphthylene -8.36E-09 8.36E-09 --No
Anthracene -1.11E-08 1.11E-08 --No
Benz(a)anthracene -8.36E-09 8.36E-09 --No
Benzene -9.76E-06 9.76E-06 0.31627362 NoBenzo(a)pyrene -5.57E-09 5.57E-09 --No
Benzo(b)fluoranthene -8.36E-09 8.36E-09 --NoBenzo(g,h,i)perylene -5.57E-09 5.57E-09 --No
Chrysene -8.36E-09 8.36E-09 --NoDibenzo(a,h) anthracene -5.57E-09 5.57E-09 --No
Dichlorobenzene -5.57E-06 5.57E-06 --No
Fluoranthene -1.39E-08 1.39E-08 --No
Fluorene -1.30E-08 1.30E-08 --No
Formaldehyde -3.48E-04 0.0003 0.0567438 NoHexane-8.36E-03 8.36E-03 34.8949693 No
Indeno(1,2,3-cd)pyrene -8.36E-09 8.36E-09 --NoNaphthalene-2.83E-06 2.83E-06 10.3810307 No
Phenanthrene -7.90E-08 7.90E-08 --NoPyrene-2.32E-08 2.32E-08 --No
Toluene -1.58E-05 1.58E-05 14.9216687 No
H2S 0.1042 0.0021 0.00 0.2760 No
1. The Emission Threshold Value (ETV) assumes <50 m distance to the fenceline and vertically unrestricted releases.
Table B-3. Maximum Hourly HAP Emissions
Scenario 1a Scenario 1b
2-Methylnaphthalene -2.11E-07 2.11E-07 --No
3-Methylcholanthrene -1.58E-08 1.58E-08 --No7,12-Dimethylbenz(a)anthracene -1.40E-07 1.40E-07 --No
Acenaphthene -1.58E-08 1.58E-08 --No
Acenaphthylene -1.58E-08 1.58E-08 --No
Anthracene -2.11E-08 2.11E-08 --No
Benz(a)anthracene -1.58E-08 1.58E-08 --NoBenzene-1.84E-05 1.84E-05 0.31627362 No
Benzo(a)pyrene -1.05E-08 1.05E-08 --NoBenzo(b)fluoranthene -1.58E-08 1.58E-08 --No
Benzo(g,h,i)perylene -1.05E-08 1.05E-08 --NoChrysene-1.58E-08 1.58E-08 --No
Dibenzo(a,h) anthracene -1.05E-08 1.05E-08 --No
Dichlorobenzene -1.05E-05 1.05E-05 --No
Fluoranthene -2.63E-08 2.63E-08 --No
Fluorene -2.46E-08 2.46E-08 --NoFormaldehyde-6.58E-04 0.0007 0.0567438 No
Hexane -1.58E-02 1.58E-02 34.8949693 NoIndeno(1,2,3-cd)pyrene -1.58E-08 1.58E-08 --No
Naphthalene -5.35E-06 5.35E-06 10.3810307 NoPhenanthrene-1.49E-07 1.49E-07 --No
Pyrene -4.39E-08 4.39E-08 --No
Toluene -2.98E-05 2.98E-05 14.9216687 No
H2S 0.2154 0.0043 0.22 0.2760 No
Table B-4. Maximum Hourly SO2 Emissions
Scenario 1a Scenario 1b
0.000 0.403 0.403
Maximum
Emissions
(lb/hr)
SO2 Emissions (lb/hr)
Modeling
Required?
Modeling
Required?Pollutant Maximum
Emissions (lb/hr)
Pollutant
ETV1
(lb/hr)
Average
Emissions (lb/hr)ETV1
(lb/hr)
Average Hourly Emissions
Maximum Hourly
Emissions (lb/hr)
GreenGasUSA 10/1/2024 Page 2 of 6
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-5. Operations
Scenario Scenario
Number
Scenario
Description Quantity Units Quantity Units
1a Treated Tail Gas
Emitted 365 days/yr 8,760 Hours/year
1b Treated Tail Gas
Combusted 365 days/yr 8,760 Hours/year
Table B-6. Raw and Tail Gas Information
Parameter
Raw (Pre-VAV
+ Molegate
PSA)
Tail (Post-VAV
+ Molegate
PSA)
Unit
H2S Concentration (treated)50 142.35 ppmv
H2S Concentration (untreated)1500 4270.5 ppmv
CH4 Concentration 70 10 %
CO2 Concentration 30 90 %
Gas Flow (average) 410 144 acfm
Gas Flow (maximum) 775 262 acfm
Gas Pressure (average)1 2 psig
Gas Pressure (maximum)1 4 psig
Gas Temperature (actual)80 90 °F
Atmospheric pressure in Hyrum, UT 12.7 12.7 psia
Table B-7. Flare Pilot/Purge Gas Combustion Emissions - Controlled Operation
Parameter Value Unit
H2S Destruction Efficiency1 98%%
Pilot/Purge Gas Flow1 100 scf/hr
Enrichment Gas Flow (average)1 60 scfm
Enrichment Gas Flow (maximum)1 112 scfm
Pilot/Purge Heat Content2 1,020 Btu/scf
Enrichment Gas Heat Content2 1,020 Btu/scf
2. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-8. Fugitive Source Parameters1
Equipment Type Quantity of each
(#)
Valves - Gas 30
Flanges - Gas 60
Compressor Seals - Gas 3
Relief Valves - Gas 15
Sampling Connection - Gas 3
1. Used to calculate fugitive emissions from connections in process equipment
Days/Yr Running Various Operations
Raw and Tail Gas Information
Flare Information
1. Pilot/purge gas volume based on manufacturer design.
Normal (VAV operational)
GreenGasUSA 10/1/2024 Page 3 of 6
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Emissions - Scenario 1
Table B-9. Treated Tail Gas Parameters
Annual Operation 8,760 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (maximum)4.00 psigTail Gas Temperature (actual)549.67 °RTail Gas Flow (average - std conditions)1,2 9,455 scf/hr
Tail Gas Flow (maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 142 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 psia
2. Conversion factors:
60 min/hr
Table B-10. Treated Tail Gas Composition
Pollutant H2S SO2 CH4 CO2
Concentration 0.014%0.000%10.00%90.00%
Average Flow Rate (scf/hr)1 1.35 0.00 945.48 8,509Maximum Flow Rate (scf/hr)2 2.78 0.00 1954.30 17588.69
Concentration 0.0003%0.014%-90.00%
Average Flow Rate (scf/hr)1 0.03 1.32 -8509.33Maximum Flow Rate (scf/hr)2 0.06 2.73 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
1. Flow Rate (scf/hr) = Concentration (%) * Tail Gas Flow (scf/hr)
Table B-11. Secnario 1a - Emissions from Treated Tail Gas
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 1.35 3.07E-03 0.10 0.46 2.78 6.34E-03 0.22 0.94
CO2 8509.33 19.38 852.76 3735.07 17588.69 40.06 1762.64 7720.34
CH4 945.48 2.15 34.45 150.91 1954.30 4.45 71.22 311.93
CO2e --1714.12 7507.87 --3543.07 15518.67
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-12. Scenario 1b - Emissions from Treated and Flared Tail Gas
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow
Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
H2S 0.03 6.13E-05 2.08E-03 9.13E-03 0.06 1.27E-04 4.31E-03 0.02
SO2 1.32 0.00 0.19 0.84 2.73 0.01 0.40 1.74
CO2 8509.33 19.38 852.76 3735.07 17588.69 40.06 640.96 2807.40
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Tail Gas Information
Average Flow Rates Maximum Flow Rates
After Flare (Scenario 1b)
Average Flow Rates Maximum Flow Rates
Before Flare (Scenario 1a)
Constituent
Constituent
GreenGasUSA 10/1/2024 Page 4 of 6
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Flaring Emissions - Scenario 1b
Table B-13. Treated Tail Gas Flaring Parameters
Annual Operation 8760 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrAverage Enrichment Gas Flow 3,600 scf/hr
Maximum Enrichment Gas Flow 6,720 scf/hrAverage Methane Gas Flow from
Tail Gas Stream2 945.48 scf/hrAverage Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Tail Gas Stream2 1954.30 scf/hr
Maximum Total Natural Gas Flow 8774.30 scf/hrNatural Gas Higher Heating Value
(HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-14. Treated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)NOX 0.1380 lb/MMBtu 6.54E-01 2.86E+00 1.24E+00 5.41E+00
CO 0.31 lb/MMBtu 1.47E+00 6.43 2.77E+00 12.15VOC 0.66 lb/MMBtu 3.13E+00 13.70 5.91E+00 25.87PM7.60 lb/MMscf 3.53E-02 1.55E-01 6.67E-02 2.92E-01PM (con)5.70 lb/MMscf 2.65E-02 1.16E-01 5.00E-02 2.19E-01PM (fil)1.90 lb/MMscf 8.83E-03 3.87E-02 1.67E-02 7.30E-02SO20.60 lb/MMscf 2.79E-03 1.22E-02 5.26E-03 2.31E-02
CO25 119316.82 lb/MMscf 5.54E+02 2.43E+03 1.05E+03 4.59E+03
CH45 2.25 lb/MMscf 1.04E-02 4.58E-02 1.97E-02 8.64E-02
N2O5 0.22 lb/MMscf 1.04E-03 4.58E-03 1.97E-03 8.64E-03
CO2e6 119440.05 lb/MMscf 5.55E+02 2.43E+03 1.05E+03 4.59E+03
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH41.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-15. Treated Tail Gas Flaring HAP Emission Factors
Hourly
Emission
Annual
Emissions
Hourly
Emission
Annual
EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)Benzene 2.10E-03 lb/MMscf 9.76E-06 4.27E-05 1.84E-05 8.07E-052-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.88E-07 2.11E-07 9.22E-073-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 3.26E-07 1.40E-07 6.15E-07
Acenaphthene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08
Acenaphthylene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.88E-08 2.11E-08 9.22E-08Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.44E-08 1.05E-08 4.61E-08
Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.44E-08 1.05E-08 4.61E-08
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.44E-08 1.05E-08 4.61E-08Dichlorobenzene1.20E-03 lb/MMscf 5.57E-06 2.44E-05 1.05E-05 4.61E-05
Fluoranthene 3.00E-06 lb/MMscf 1.39E-08 6.10E-08 2.63E-08 1.15E-07
Fluorene 2.80E-06 lb/MMscf 1.30E-08 5.70E-08 2.46E-08 1.08E-07
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.53E-03 6.58E-04 2.88E-03
Hexane 1.8 lb/MMscf 8.36E-03 3.66E-02 1.58E-02 6.92E-02
Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.66E-08 1.58E-08 6.92E-08Naphthalene6.10E-04 lb/MMscf 2.83E-06 1.24E-05 5.35E-06 2.34E-05
Phenanthrene 1.70E-05 lb/MMscf 7.90E-08 3.46E-07 1.49E-07 6.53E-07
Pyrene 5.00E-06 lb/MMscf 2.32E-08 1.02E-07 4.39E-08 1.92E-07
Toluene 3.40E-03 lb/MMscf 1.58E-05 6.92E-05 2.98E-05 1.31E-048.74E-03 3.83E-02 1.65E-02 7.23E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Total HAPs
Flare Information
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor1
GreenGasUSA 10/1/2024 Page 5 of 6
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Fugitive emissions
Table B-16. Fugitive Emission Factors Table B-17. Speciated Gas Components
Component wt%1
H2S wt%0.15%
(lb/hr/source)CO2 wt%30.00%
Valves - Gas 0.01320 30 CH4 wt%70.00%
Flanges - Gas 0.00390 60 1. Raw gas composition used for fugitive calculations
Compressor Seals - Gas 0.50270 3
Relief Valves - Gas 0.22930 15
Sampling Connection - Gas 0.03300 3
Table B-18. Emission Rates for CO2 and CH4
(lb/hr)(tpy)(lb/hr)(tpy)(lb/hr)(tpy)
Valves - Gas 0.12 0.52 0.28 1.21 7.05 30.87
Flanges - Gas 0.07 0.31 0.16 0.72 4.17 18.24
Compressor Seals - Gas 0.45 1.98 1.06 4.62 26.84 117.58Relief Valves - Gas 1.03 4.52 2.41 10.55 61.22 268.16Other - Gas 0.03 0.13 0.07 0.30 1.76 7.72
Total 1.70 7.46 3.97 17.40 101.04 442.57
1. Hours of operations:8760
2. Global Warming Potential of CH4 from 40 CFR 98 Table A-1 25
Table B-19. Emission Rate for H2S
(lb/hr)(tpy)
Valves - Gas 5.94E-04 2.60E-03
Flanges - Gas 3.51E-04 1.54E-03
Compressor Seals - Gas 2.26E-03 9.91E-03Relief Valves - Gas 5.16E-03 0.02Other - Gas 1.49E-04 6.50E-04Total0.01 0.04
H2S Emission RateEquipment Type
Equipment Type CO2e Emission Rate1,2
Equipment Type
Uncontrolled
Emission
Factor1 Source
Count
1. Factors are from TCEQ Air Permit Technical Guidance for Chemical Sources: Fugitive Guidance. Emission Factors - Oil and Gas Production
Operations, June 2018.
CO2 Emission Rate CH4 Emission Rate
GreenGasUSA 10/1/2024 Page 6 of 6
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-1. GreenGasUSA Potential To Emit Annual Emissions Summary
NOX NO2 CO PM10 PM2.5 SO2 VOC CO2e H2S Total HAPs
1a Treated Tail Gas Emitted -------14243.16 0.87 0.00
1b Treated Tail Gas Combusted 4.96 4.96 11.15 0.27 0.27 1.62 23.75 6789.62 0.02 0.072aUntreated Tail Gas Combusted 0.44 0.44 1.00 0.02 0.02 4.29 2.13 1011.83 0.05 0.012bRaw Gas Combusted 1.72 1.72 3.86 0.09 0.09 3.73 8.22 1980.93 0.04 0.02-------442.57 0.04 0.00
6.68 6.68 15.01 0.36 0.36 5.91 31.96 16666.66 0.95 0.09
100 100 250 250 100 100 250 100,000 -10/25NoNoNoNoNoNoNoNo-No
40 40 100 15 10 40 ----See HAPS
Summary
See HAPS
SummaryNoNoNoNoNoNoNoNoNoNo
1. Facility wide PTE is calculated by summing the maximum of scenarios 1a and 1b with the maximum of scenarios 2a and 2b, including fugitive emissions
2. Major source thresholds are defined by 40 CFR section 52.21(b)(1).
3. Modeling Limit is stated in UDAQ Emissions Impact Assessment Guidelines under Table 1: Total Controlled Emission Rates for New Sources or Emissions Increase.
Maximum Potential To Emit (tpy)
Major Source Thresholds2
Threshold Exceeded?
Modeling Limits3
Threshold Exceeded?
Scenario Description
Fugitives
Scenario Number
Facility Wide PTE1
Scenario
Normal (VAV operational)
Emergency/Maintenance (VAV not operational)
GreenGasUSA 8/9/2024 Page 1 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-2. Average Potential HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b2-Methylnaphthalene -1.11E-07 1.11E-07 4.32E-07 4.32E-07 --No3-Methylcholanthrene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
7,12-Dimethylbenz(a)anthracene -7.43E-08 7.43E-08 2.88E-07 2.88E-07 --No
Acenaphthene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
Acenaphthylene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
Anthracene -1.11E-08 1.11E-08 4.32E-08 4.32E-08 --NoBenz(a)anthracene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --NoBenzene-9.76E-06 9.76E-06 3.78E-05 3.78E-05 0.31627362 No
Benzo(a)pyrene -5.57E-09 5.57E-09 2.16E-08 2.16E-08 --No
Benzo(b)fluoranthene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
Benzo(g,h,i)perylene -5.57E-09 5.57E-09 2.16E-08 2.16E-08 --No
Chrysene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --NoDibenzo(a,h) anthracene -5.57E-09 5.57E-09 2.16E-08 2.16E-08 --NoDichlorobenzene-5.57E-06 5.57E-06 2.16E-05 2.16E-05 --No
Fluoranthene -1.39E-08 1.39E-08 5.40E-08 5.40E-08 --No
Fluorene -1.30E-08 1.30E-08 5.04E-08 5.04E-08 --No
Formaldehyde -3.48E-04 3.48E-04 1.35E-03 0.0013 0.0567438 No
Hexane -8.36E-03 8.36E-03 3.24E-02 3.24E-02 34.8949693 NoIndeno(1,2,3-cd)pyrene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --NoNaphthalene-2.83E-06 2.83E-06 1.10E-05 1.10E-05 10.3810307 NoPhenanthrene-7.90E-08 7.90E-08 3.06E-07 3.06E-07 --No
Pyrene -2.32E-08 2.32E-08 8.99E-08 8.99E-08 --No
Toluene -1.58E-05 1.58E-05 6.12E-05 6.12E-05 14.9216687 No
H2S 0.1042 0.0021 0.0625 0.0594 0.06 0.2760 No
1. The Emission Threshold Value (ETV) assumes <50 m distance to the fenceline and vertically unrestricted releases.
Table B-3. Maximum Hourly HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b
2-Methylnaphthalene -2.11E-07 2.11E-07 8.14E-07 8.14E-07 --No
3-Methylcholanthrene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
7,12-Dimethylbenz(a)anthracene -1.40E-07 1.40E-07 5.43E-07 5.43E-07 --NoAcenaphthene-1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoAcenaphthylene-1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoAnthracene-2.11E-08 2.11E-08 8.14E-08 8.14E-08 --No
Benz(a)anthracene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Benzene -1.84E-05 1.84E-05 7.12E-05 7.12E-05 0.31627362 No
Benzo(a)pyrene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --No
Benzo(b)fluoranthene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoBenzo(g,h,i)perylene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --NoChrysene-1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Dibenzo(a,h) anthracene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --No
Dichlorobenzene -1.05E-05 1.05E-05 4.07E-05 4.07E-05 --No
Fluoranthene -2.63E-08 2.63E-08 1.02E-07 1.02E-07 --No
Fluorene -2.46E-08 2.46E-08 9.50E-08 9.50E-08 --NoFormaldehyde-6.58E-04 6.58E-04 2.54E-03 0.0025 0.0567438 NoHexane-1.58E-02 1.58E-02 6.10E-02 6.10E-02 34.8949693 No
Indeno(1,2,3-cd)pyrene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Naphthalene -5.35E-06 5.35E-06 2.07E-05 2.07E-05 10.3810307 No
Phenanthrene -1.49E-07 1.49E-07 5.76E-07 5.76E-07 --No
Pyrene -4.39E-08 4.39E-08 1.70E-07 1.70E-07 --NoToluene-2.98E-05 2.98E-05 1.15E-04 1.15E-04 14.9216687 No
H2S 0.2154 0.0043 0.1293 0.1122 0.22 0.2760 No
Modeling
Required?
Modeling
Required?
Average Hourly Emissions (lb/hr)
Pollutant Maximum Hourly Emissions (lb/hr)Maximum
Emissions (lb/hr)
Pollutant
ETV1
(lb/hr)
Average
Emissions (lb/hr)ETV1
(lb/hr)
GreenGasUSA 8/9/2024 Page 2 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-4. Operations
Scenario Scenario
Number
Scenario
Description Quantity Units Quantity Units
1a Treated Tail Gas
Emitted 335 days/yr 8,040 Hours/year
1b Treated Tail Gas
Combusted 335 days/yr 8,040 Hours/year
2a Untreated Tail
Gas Combusted 30 days/yr 720 Hours/year
2b Raw Gas
Combusted 30 days/yr 720 Hours/year
Table B-5. Raw and Tail Gas Information
Parameter
Raw (Pre-VAV
+ Molegate
PSA)
Tail (Post-VAV
+ Molegate
PSA)
Unit
H2S Concentration (treated)50 142.35 ppmv
H2S Concentration (untreated)1500 4270.5 ppmv
CH4 Concentration 70 10 %
CO2 Concentration 30 90 %
Gas Flow (average) 410 144 acfm
Gas Flow (maximum) 775 262 acfm
Gas Pressure (average)1 2 psig
Gas Pressure (maximum)1 4 psig
Gas Temperature (actual)80 90 °F
Atmospheric pressure in Hyrum, UT 12.7 12.7 psia
Table B-6. Flare Pilot/Purge Gas Combustion Emissions - Controlled Operation
Parameter Value Unit
H2S Destruction Efficiency1 98%%
Pilot/Purge Gas Flow1 100 scf/hr
Enrichment Gas Flow (average)1 60 scfm
Enrichment Gas Flow (maximum)1 112 scfm
Pilot/Purge Heat Content2 1,020 Btu/scf
Enrichment Gas Heat Content2 1,020 Btu/scf
2. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-7. Fugitive Source Parameters1
Equipment Type Quantity of each
(#)
Valves - Gas 30
Flanges - Gas 60
Compressor Seals - Gas 3
Relief Valves - Gas 15
Sampling Connection - Gas 3
1. Used to calculate fugitive emissions from connections in process equipment
Days/Yr Running Various Operations
Raw and Tail Gas Information
Flare Information
1. Pilot/purge gas volume based on manufacturer design.
Normal (VAV operational)
Emergency/Maintenance (VAV not
operational)
GreenGasUSA 8/9/2024 Page 3 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Emissions - Scenario 1
Table B-8. Treated Tail Gas Parameters
Annual Operation 8,040 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (maximum)4.00 psig
Tail Gas Temperature (actual)549.67 °R
Tail Gas Flow (average - std conditions)1,2 9,455 scf/hr
Tail Gas Flow (maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 142 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 psia
2. Conversion factors:
60 min/hr
Table B-9. Treated Tail Gas Composition
Pollutant H2S SO2 CH4 CO2
Concentration 0.014%0.000%10.00%90.00%
Average Flow Rate (scf/hr)1 1.35 0.00 945.48 8,509
Maximum Flow Rate (scf/hr)2 2.78 0.00 1954.30 17588.69
Concentration 0.0003%0.014%-90.00%
Average Flow Rate (scf/hr)1 0.03 1.32 -8509.33Maximum Flow Rate (scf/hr)2 0.06 2.73 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
1. Flow Rate (scf/hr) = Concentration (%) * Tail Gas Flow (scf/hr)
Table B-10. Secnario 1a - Emissions from Treated Tail Gas
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow
Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 1.35 3.07E-03 0.10 0.42 2.78 6.34E-03 0.22 0.87
CO2 8509.33 19.38 852.76 3428.08 17588.69 40.06 1762.64 7085.79
CH4 945.48 2.15 34.45 138.51 1954.30 4.45 71.22 286.29
CO2e --1714.12 6890.78 --3543.07 14243.16
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-11. Scenario 1b - Emissions from Treated and Flared Tail Gas
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
H2S 0.03 6.13E-05 2.08E-03 8.38E-03 0.06 1.27E-04 4.31E-03 0.02
SO2 1.32 0.00 0.19 0.77 2.73 0.01 0.40 1.60
CO2 8509.33 19.38 852.76 3428.08 17588.69 40.06 640.96 2576.65
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Tail Gas Information
Average Flow Rates Maximum Flow Rates
After Flare (Scenario 1b)
Average Flow Rates Maximum Flow Rates
Before Flare (Scenario 1a)
Constituent
Constituent
GreenGasUSA 8/9/2024 Page 4 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Flaring Emissions - Scenario 1b
Table B-12. Treated Tail Gas Flaring Parameters
Annual Operation 8040 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrAverage Enrichment Gas Flow 3,600 scf/hr
Maximum Enrichment Gas Flow 6,720 scf/hrAverage Methane Gas Flow from
Tail Gas Stream2 945.48 scf/hr
Average Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Tail Gas Stream2 1954.30 scf/hr
Maximum Total Natural Gas Flow 8774.30 scf/hr
Natural Gas Higher Heating Value
(HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-13. Treated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual
Emissions (tpy)
Hourly
Emissions4
(lb/hr)
Annual
Emissions (tpy)NOX 0.1380 lb/MMBtu 6.54E-01 2.63E+00 1.24E+00 4.96E+00
CO 0.31 lb/MMBtu 1.47E+00 5.90 2.77E+00 11.15
VOC 0.66 lb/MMBtu 3.13E+00 12.57 5.91E+00 23.75PM7.60 lb/MMscf 3.53E-02 1.42E-01 6.67E-02 2.68E-01PM (con)5.70 lb/MMscf 2.65E-02 1.06E-01 5.00E-02 2.01E-01
PM (fil)1.90 lb/MMscf 8.83E-03 3.55E-02 1.67E-02 6.70E-02
SO2 0.60 lb/MMscf 2.79E-03 1.12E-02 5.26E-03 2.12E-02
CO25 119316.82 lb/MMscf 5.54E+02 2.23E+03 1.05E+03 4.21E+03
CH45 2.25 lb/MMscf 1.04E-02 4.20E-02 1.97E-02 7.93E-02
N2O5 0.22 lb/MMscf 1.04E-03 4.20E-03 1.97E-03 7.93E-03
CO2e6 119440.05 lb/MMscf 5.55E+02 2.23E+03 1.05E+03 4.21E+03
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-14. Treated Tail Gas Flaring HAP Emission Factors
Hourly
Emission
Annual
Emissions
Hourly
Emission
Annual
EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)
Benzene 2.10E-03 lb/MMscf 9.76E-06 3.92E-05 1.84E-05 7.41E-05
2-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.48E-07 2.11E-07 8.47E-073-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 2.99E-07 1.40E-07 5.64E-07Acenaphthene1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Acenaphthylene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.48E-08 2.11E-08 8.47E-08
Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 1.05E-08 4.23E-08Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 1.05E-08 4.23E-08
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 1.05E-08 4.23E-08
Dichlorobenzene 1.20E-03 lb/MMscf 5.57E-06 2.24E-05 1.05E-05 4.23E-05Fluoranthene3.00E-06 lb/MMscf 1.39E-08 5.60E-08 2.63E-08 1.06E-07
Fluorene 2.80E-06 lb/MMscf 1.30E-08 5.23E-08 2.46E-08 9.88E-08
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.40E-03 6.58E-04 2.65E-03Hexane1.8 lb/MMscf 8.36E-03 3.36E-02 1.58E-02 6.35E-02
Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08Naphthalene6.10E-04 lb/MMscf 2.83E-06 1.14E-05 5.35E-06 2.15E-05
Phenanthrene 1.70E-05 lb/MMscf 7.90E-08 3.17E-07 1.49E-07 6.00E-07
Pyrene 5.00E-06 lb/MMscf 2.32E-08 9.34E-08 4.39E-08 1.76E-07
Toluene 3.40E-03 lb/MMscf 1.58E-05 6.35E-05 2.98E-05 1.20E-04
8.74E-03 3.52E-02 1.65E-02 6.64E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Total HAPs
Flare Information
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor1
GreenGasUSA 8/9/2024 Page 5 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Untreated and Flared Tail Gas - Scenario 2a
Table B-15. Untreated Tail Gas Parameters
Annual Operation 720 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (maximum)4.00 psig
Tail gas Temperature (actual)549.67 °R
Tail Gas Flow (average - std conditions) 1,2 9,455 scf/hr
Tail Gas Flow (maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 4,271 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 pisa
2. Conversion factors:
60 min/hr
Table B-16. Untreated Tail Gas Composition
H2S SO2 CH4 CO2
Concentration1,2 (%)0.427%0.000%10.00%90.00%
Average Flow Rate3 (scf/hr)40.38 0.00 945.48 8509.33
Maximum Flow Rate3 (scf/hr)83.46 0.00 1954.30 17588.69
Concentration1,2 (%)0.0085%0.419%-90.00%
Average Flow Rate3 (scf/hr)0.81 39.57 -8509.33Maximum Flow Rate3 (scf/hr)1.67 81.79 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted. See emissons from CH4 combustion on next page.
3. Flow Rate (scf/hr) = Concentration (%) * Raw Gas Flow (std conditions)(scf/hr)
Table B-17. Untreated Tail Gas Combusted Emissions
Volume Flow
Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume
Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 0.81 1.84E-03 0.06 0.02 1.67 3.80E-03 0.13 0.05
SO2 39.57 0.09 5.77 2.08 81.79 1.86E-01 11.92 4.29
CO2 8509.33 19.38 852.76 306.99 17588.69 4.01E+01 1762.64 634.55
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressur 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempatur 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
Average Flow Rates Maximum Flow Rates
Constituent
Tail Gas Information
Before Flare
After Flare
GreenGasUSA 8/9/2024 Page 6 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Untreated Tail Gas - Scenario 2a
Table B-18. Untreated Tail Gas Flaring Parameters
Annual Operation 720 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrEnrichment Gas Flow 3,600 scf/hr
Maximum Enrichment Gas Glow 6,720 scf/hrAverage Methane Gas Flow from Untreated
Tail Gas Stream2 945.48 scf/hrAverage Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Untreated Tail Gas Stream2 1954.30 scf/hr
Maximum Total Natural Gas Flow 8774.30 scf/hr
Natural Gas Higher Heating Value (HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-19. Untreated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual Emissions (tpy)
Hourly
Emissions4
(lb/hr)
Annual Emissions (tpy)
NOX 0.1380 lb/MMBtu 6.54E-01 2.35E-01 1.24E+00 4.45E-01CO 0.31 lb/MMBtu 1.47E+00 0.53 2.77E+00 1.00VOC 0.66 lb/MMBtu 3.13E+00 1.13 5.91E+00 2.13PM7.60 lb/MMscf 3.53E-02 1.27E-02 6.67E-02 2.40E-02PM (con)5.70 lb/MMscf 2.65E-02 0.01 5.00E-02 0.02PM (fil)1.90 lb/MMscf 8.83E-03 0.00 1.67E-02 0.01SO20.60 lb/MMscf 2.79E-03 1.00E-03 5.26E-03 1.90E-03
CO25 119316.82 lb/MMscf 5.54E+02 199.54 1.05E+03 3.77E+02
CH45 2.25 lb/MMscf 1.04E-02 3.76E-03 1.97E-02 7.10E-03
N2O5 0.22 lb/MMscf 1.04E-03 3.76E-04 1.97E-03 0.00
CO2e6 119440.05 lb/MMscf 5.55E+02 200 1.05E+03 377
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-20. Misc. Natural Gas HAP Emission Factors
Hourly Emission Annual Emissions Hourly Emission Annual EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)Benzene 2.10E-03 lb/MMscf 9.76E-06 3.51E-06 1.84E-05 6.63E-06
2-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.01E-08 2.11E-07 7.58E-083-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 2.68E-08 1.40E-07 5.05E-08
Acenaphthene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Acenaphthylene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.01E-09 2.11E-08 7.58E-09
Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 1.05E-08 3.79E-09
Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 1.05E-08 3.79E-09
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 1.05E-08 3.79E-09
Dichlorobenzene 1.20E-03 lb/MMscf 5.57E-06 2.01E-06 1.05E-05 3.79E-06
Fluoranthene 3.00E-06 lb/MMscf 1.39E-08 5.02E-09 2.63E-08 9.48E-09
Fluorene 2.80E-06 lb/MMscf 1.30E-08 4.68E-09 2.46E-08 8.84E-09
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.25E-04 6.58E-04 2.37E-04
Hexane 1.8 lb/MMscf 8.36E-03 3.01E-03 1.58E-02 5.69E-03
Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Naphthalene 6.10E-04 lb/MMscf 2.83E-06 1.02E-06 5.35E-06 1.93E-06
Phenanthrene 1.70E-05 lb/MMscf 7.90E-08 2.84E-08 1.49E-07 5.37E-08Pyrene5.00E-06 lb/MMscf 2.32E-08 8.36E-09 4.39E-08 1.58E-08
Toluene 3.40E-03 lb/MMscf 1.58E-05 5.69E-06 2.98E-05 1.07E-05
8.74E-03 3.15E-03 1.65E-02 5.95E-03
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Total HAPs
Flare Information
Pollutant Emission Factor1
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
GreenGasUSA 8/9/2024 Page 7 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Raw Gas - Scenario 2b
Table B-21. Raw Gas Parameters
Annual Operation 720 hrs/yr
Average Raw Gas Flow 410 acf/minMaximum Raw Gas Flow 775 acf/min
Raw Gas Pressure 1.00 psig
Raw Gas Temperature (actual)539.67 °R
Average Raw Gas Flow (std conditions) 1,2 25,554 scf/hr
Maximum Raw Gas Flow (std conditions) 1,3 48,302 scf/hr
H2S Concentration 1,500 ppmv
1. Raw Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 pisa
2. Conversion factors:
60 min/hr
Table B-22. Raw Gas Composition
H2S SO2 CH4 CO2
Concentration1,2 (%)0.150%0.000%70.00%30.00%
Average Flow Rate3 (scf/hr)38.33 0.00 17887.49 7666.07Maximum Flow Rate3 (scf/hr)72.45 0.00 33811.72 14490.74
Concentration1,2 (%)0.0030%0.147%-30.00%
Average Flow Rate3 (scf/hr)0.77 37.56 -7666.07
Maximum Flow Rate3 (scf/hr)1.45 71.00 -14490.74
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
3. Flow Rate (scf/hr) = Concentration (%) * Raw Gas Flow (std conditions)(scf/hr)
Table B-23. Emissions from Raw Gas Combustion
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
H2S 0.77 1.75E-03 0.06 0.02 1.45 3.30E-03 0.11 0.04
SO2 37.56 0.09 5.48 1.97 71.00 0.16 10.35 3.73
CO2 7666.07 17.46 768.25 276.57 14490.74 33.00 1452.18 522.78
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressur 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempatu 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
Average Flow Rates Maximum Flow Rates
Constituent
Raw Gas Information
Before Flare
After Flare
GreenGasUSA 8/9/2024 Page 8 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Raw Gas - Scenario 2b
Table B-24. Natural Gas Parameters
Annual Operation 720 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrAverage Methane Gas Flow from Raw Gas
Stream2 17887.49 scf/hrAverage Total Natural Gas Flow 17987.49 scf/hrMaximum Methane Gas Flow from Raw
Gas Stream2 33811.72 scf/hrMaximum Total Natural Gas Flow 33911.72 scf/hr
Natural Gas Higher Heating Value (HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of raw gas is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-25. Emissions from Natural Gas
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
NOX 0.1380 lb/MMBtu 2.53E+00 0.91 4.77E+00 1.72CO 0.31 lb/MMBtu 5.69E+00 2.05 1.07E+01 3.86VOC 0.66 lb/MMBtu 1.21E+01 4.36 2.28E+01 8.22
PM 7.60 lb/MMscf 1.37E-01 0.05 2.58E-01 0.09PM (con)5.70 lb/MMscf 1.03E-01 0.04 1.93E-01 0.07PM (fil)1.90 lb/MMscf 3.42E-02 0.01 6.44E-02 0.02
SO2 0.60 lb/MMscf 1.08E-02 0.00 2.03E-02 0.01
CO25 119316.82 lb/MMscf 2.15E+03 773 4.05E+03 1,457
CH45 2.25 lb/MMscf 4.04E-02 0.01 7.63E-02 0.03
N2O5 0.22 lb/MMscf 4.04E-03 0.00 7.63E-03 0.00
CO2e6 119440.05 lb/MMscf 2.15E+03 773 4.05E+03 1,458
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-26. Misc. Natural Gas HAP Emission Factors
Hourly Annual Hourly Annual Value Unit (lb/hr)(tpy)(lb/hr)(tpy)
Benzene 2.10E-03 lb/MMscf 3.78E-05 1.36E-05 7.12E-05 2.56E-052-Methylnaphthalene 2.40E-05 lb/MMscf 4.32E-07 1.55E-07 8.14E-07 2.93E-07
3-Methylcholanthrene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 2.88E-07 1.04E-07 5.43E-07 1.95E-07Acenaphthene1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Acenaphthylene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Anthracene 2.40E-06 lb/MMscf 4.32E-08 1.55E-08 8.14E-08 2.93E-08Benz(a)anthracene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Benzo(a)pyrene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08Benzo(b)fluoranthene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Chrysene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Dichlorobenzene 1.20E-03 lb/MMscf 2.16E-05 7.77E-06 4.07E-05 1.46E-05
Fluoranthene 3.00E-06 lb/MMscf 5.40E-08 1.94E-08 1.02E-07 3.66E-08
Fluorene 2.80E-06 lb/MMscf 5.04E-08 1.81E-08 9.50E-08 3.42E-08
Formaldehyde 7.50E-02 lb/MMscf 1.35E-03 4.86E-04 2.54E-03 9.16E-04
Hexane 1.8 lb/MMscf 3.24E-02 1.17E-02 6.10E-02 2.20E-02Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Naphthalene 6.10E-04 lb/MMscf 1.10E-05 3.95E-06 2.07E-05 7.45E-06
Phenanthrene 1.70E-05 lb/MMscf 3.06E-07 1.10E-07 5.76E-07 2.08E-07Pyrene5.00E-06 lb/MMscf 8.99E-08 3.24E-08 1.70E-07 6.10E-08
Toluene 3.40E-03 lb/MMscf 6.12E-05 2.20E-05 1.15E-04 4.15E-053.39E-02 1.22E-02 6.38E-02 2.30E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Total HAPs
Flare Information
Pollutant Natural Gas1
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
GreenGasUSA 8/9/2024 Page 9 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Fugitive emissions
Table B-27. Fugitive Emission Factors Table B-28. Speciated Gas Components
Component wt%1
H2S wt%0.15%
(lb/hr/source)CO2 wt%30.00%
Valves - Gas 0.01320 30 CH4 wt%70.00%
Flanges - Gas 0.00390 60 1. Raw gas composition used for fugitive calculations
Compressor Seals - Gas 0.50270 3
Relief Valves - Gas 0.22930 15
Sampling Connection - Gas 0.03300 3
Table B-29. Emission Rates for CO2 and CH4
(lb/hr)(tpy)(lb/hr)(tpy)(lb/hr)(tpy)Valves - Gas 0.12 0.52 0.28 1.21 7.05 30.87Flanges - Gas 0.07 0.31 0.16 0.72 4.17 18.24Compressor Seals - Gas 0.45 1.98 1.06 4.62 26.84 117.58Relief Valves - Gas 1.03 4.52 2.41 10.55 61.22 268.16
Other - Gas 0.03 0.13 0.07 0.30 1.76 7.72
Total 1.70 7.46 3.97 17.40 101.04 442.57
1. Hours of operations:8760
2. Global Warming Potential of CH4 from 40 CFR 98 Table A-1 25
Table B-30. Emission Rate for H2S
(lb/hr)(tpy)Valves - Gas 5.94E-04 2.60E-03Flanges - Gas 3.51E-04 1.54E-03Compressor Seals - Gas 2.26E-03 9.91E-03Relief Valves - Gas 5.16E-03 0.02
Other - Gas 1.49E-04 6.50E-04
Total 0.01 0.04
H2S Emission RateEquipment Type
Equipment Type CO2e Emission Rate1,2
Equipment Type
Uncontrolled
Emission
Factor1 Source
Count
1. Factors are from TCEQ Air Permit Technical Guidance for Chemical Sources: Fugitive Guidance. Emission Factors - Oil and Gas Production
Operations, June 2018.
CO2 Emission Rate CH4 Emission Rate
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GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-1. GreenGasUSA Potential To Emit Annual Emissions Summary
NOX NO2 CO PM10 PM2.5 SO2 VOC CO2e H2S Total HAPs
1a Treated Tail Gas Emitted -------14243.16 0.87 0.00
1b Treated Tail Gas Combusted 4.96 4.96 11.15 0.27 0.27 0.02 23.75 6789.62 0.02 0.072aUntreated Tail Gas Combusted 0.44 0.44 1.00 0.02 0.02 4.29 2.13 1011.83 0.05 0.012bRaw Gas Combusted 1.72 1.72 3.86 0.09 0.09 3.73 8.22 1980.93 0.04 0.02-------442.57 0.04 0.00
6.68 6.68 15.01 0.36 0.36 4.32 31.96 16666.66 0.95 0.09
100 100 250 250 100 100 250 100,000 -10/25NoNoNoNoNoNoNoNo-No
40 40 100 15 10 40 ----See HAPS
Summary
See HAPS
SummaryNoNoNoNoNoNoNoNoNoNo
1. Facility wide PTE is calculated by summing the maximum of scenarios 1a and 1b with the maximum of scenarios 2a and 2b, including fugitive emissions
2. Major source thresholds are defined by 40 CFR section 52.21(b)(1).
3. Modeling Limit is stated in UDAQ Emissions Impact Assessment Guidelines under Table 1: Total Controlled Emission Rates for New Sources or Emissions Increase.
Modeling Limits3
Threshold Exceeded?
Scenario Description
Fugitives
Scenario Number
Facility Wide PTE1
Scenario
Normal (VAV operational)
Emergency/Maintenance (VAV not operational)
Maximum Potential To Emit (tpy)
Major Source Thresholds2
Threshold Exceeded?
GreenGasUSA 8/9/2024 Page 1 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-2. Average Potential HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b2-Methylnaphthalene -1.11E-07 1.11E-07 4.32E-07 4.32E-07 --No3-Methylcholanthrene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
7,12-Dimethylbenz(a)anthracene -7.43E-08 7.43E-08 2.88E-07 2.88E-07 --No
Acenaphthene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
Acenaphthylene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
Anthracene -1.11E-08 1.11E-08 4.32E-08 4.32E-08 --NoBenz(a)anthracene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --NoBenzene-9.76E-06 9.76E-06 3.78E-05 3.78E-05 0.31627362 No
Benzo(a)pyrene -5.57E-09 5.57E-09 2.16E-08 2.16E-08 --No
Benzo(b)fluoranthene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --No
Benzo(g,h,i)perylene -5.57E-09 5.57E-09 2.16E-08 2.16E-08 --No
Chrysene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --NoDibenzo(a,h) anthracene -5.57E-09 5.57E-09 2.16E-08 2.16E-08 --NoDichlorobenzene-5.57E-06 5.57E-06 2.16E-05 2.16E-05 --No
Fluoranthene -1.39E-08 1.39E-08 5.40E-08 5.40E-08 --No
Fluorene -1.30E-08 1.30E-08 5.04E-08 5.04E-08 --No
Formaldehyde -3.48E-04 3.48E-04 1.35E-03 0.0013 0.0567438 No
Hexane -8.36E-03 8.36E-03 3.24E-02 3.24E-02 34.8949693 NoIndeno(1,2,3-cd)pyrene -8.36E-09 8.36E-09 3.24E-08 3.24E-08 --NoNaphthalene-2.83E-06 2.83E-06 1.10E-05 1.10E-05 10.3810307 NoPhenanthrene-7.90E-08 7.90E-08 3.06E-07 3.06E-07 --No
Pyrene -2.32E-08 2.32E-08 8.99E-08 8.99E-08 --No
Toluene -1.58E-05 1.58E-05 6.12E-05 6.12E-05 14.9216687 No
H2S 0.1042 0.0021 0.0625 0.0594 0.06 0.2760 No
1. The Emission Threshold Value (ETV) assumes <50 m distance to the fenceline and vertically unrestricted releases.
Table B-3. Maximum Hourly HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b
2-Methylnaphthalene -2.11E-07 2.11E-07 8.14E-07 8.14E-07 --No
3-Methylcholanthrene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
7,12-Dimethylbenz(a)anthracene -1.40E-07 1.40E-07 5.43E-07 5.43E-07 --NoAcenaphthene-1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoAcenaphthylene-1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoAnthracene-2.11E-08 2.11E-08 8.14E-08 8.14E-08 --No
Benz(a)anthracene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Benzene -1.84E-05 1.84E-05 7.12E-05 7.12E-05 0.31627362 No
Benzo(a)pyrene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --No
Benzo(b)fluoranthene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoBenzo(g,h,i)perylene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --NoChrysene-1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Dibenzo(a,h) anthracene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --No
Dichlorobenzene -1.05E-05 1.05E-05 4.07E-05 4.07E-05 --No
Fluoranthene -2.63E-08 2.63E-08 1.02E-07 1.02E-07 --No
Fluorene -2.46E-08 2.46E-08 9.50E-08 9.50E-08 --NoFormaldehyde-6.58E-04 6.58E-04 2.54E-03 0.0025 0.0567438 NoHexane-1.58E-02 1.58E-02 6.10E-02 6.10E-02 34.8949693 No
Indeno(1,2,3-cd)pyrene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Naphthalene -5.35E-06 5.35E-06 2.07E-05 2.07E-05 10.3810307 No
Phenanthrene -1.49E-07 1.49E-07 5.76E-07 5.76E-07 --No
Pyrene -4.39E-08 4.39E-08 1.70E-07 1.70E-07 --NoToluene-2.98E-05 2.98E-05 1.15E-04 1.15E-04 14.9216687 No
H2S 0.2154 0.0043 0.1293 0.1122 0.22 0.2760 No
Modeling
Required?
Modeling
Required?
Average Hourly Emissions (lb/hr)
Pollutant Maximum Hourly Emissions (lb/hr)Maximum
Emissions (lb/hr)
Pollutant
ETV1
(lb/hr)
Average
Emissions (lb/hr)ETV1
(lb/hr)
GreenGasUSA 8/9/2024 Page 2 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-4. Operations
Scenario Scenario
Number
Scenario
Description Quantity Units Quantity Units
1a Treated Tail Gas
Emitted 335 days/yr 8,040 Hours/year
1b Treated Tail Gas
Combusted 335 days/yr 8,040 Hours/year
2a Untreated Tail
Gas Combusted 30 days/yr 720 Hours/year
2b Raw Gas
Combusted 30 days/yr 720 Hours/year
Table B-5. Raw and Tail Gas Information
Parameter
Raw (Pre-VAV
+ Molegate
PSA)
Tail (Post-VAV
+ Molegate
PSA)
Unit
H2S Concentration (treated)50 142.35 ppmv
H2S Concentration (untreated)1500 4270.5 ppmv
CH4 Concentration 70 10 %
CO2 Concentration 30 90 %
Gas Flow (average) 410 144 acfm
Gas Flow (maximum) 775 262 acfm
Gas Pressure (average)1 2 psig
Gas Pressure (maximum)1 4 psig
Gas Temperature (actual)80 90 °F
Atmospheric pressure in Hyrum, UT 12.7 12.7 psia
Table B-6. Flare Pilot/Purge Gas Combustion Emissions - Controlled Operation
Parameter Value Unit
H2S Destruction Efficiency1 98%%
Pilot/Purge Gas Flow1 100 scf/hr
Enrichment Gas Flow (average)1 60 scfm
Enrichment Gas Flow (maximum)1 112 scfm
Pilot/Purge Heat Content2 1,020 Btu/scf
Enrichment Gas Heat Content2 1,020 Btu/scf
2. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-7. Fugitive Source Parameters1
Equipment Type Quantity of each
(#)
Valves - Gas 30
Flanges - Gas 60
Compressor Seals - Gas 3
Relief Valves - Gas 15
Sampling Connection - Gas 3
1. Used to calculate fugitive emissions from connections in process equipment
Days/Yr Running Various Operations
Raw and Tail Gas Information
Flare Information
1. Pilot/purge gas volume based on manufacturer design.
Normal (VAV operational)
Emergency/Maintenance (VAV not
operational)
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GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Emissions - Scenario 1
Table B-8. Treated Tail Gas Parameters
Annual Operation 8,040 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (maximum)4.00 psig
Tail Gas Temperature (actual)549.67 °R
Tail Gas Flow (average - std conditions)1,2 9,455 scf/hr
Tail Gas Flow (maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 142 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 psia
2. Conversion factors:
60 min/hr
Table B-9. Treated Tail Gas Composition
Pollutant H2S SO2 CH4 CO2
Concentration 0.014%0.000%10.00%90.00%
Average Flow Rate (scf/hr)1 1.35 0.00 945.48 8,509
Maximum Flow Rate (scf/hr)2 2.78 0.00 1954.30 17588.69
Concentration 0.0003%0.014%-90.00%
Average Flow Rate (scf/hr)1 0.03 1.32 -8509.33Maximum Flow Rate (scf/hr)2 0.06 2.73 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
1. Flow Rate (scf/hr) = Concentration (%) * Tail Gas Flow (scf/hr)
Table B-10. Secnario 1a - Emissions from Treated Tail Gas
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow
Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 1.35 3.07E-03 0.10 0.42 2.78 6.34E-03 0.22 0.87
CO2 8509.33 19.38 852.76 3428.08 17588.69 40.06 1762.64 7085.79
CH4 945.48 2.15 34.45 138.51 1954.30 4.45 71.22 286.29
CO2e --1714.12 6890.78 --3543.07 14243.16
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-11. Scenario 1b - Emissions from Treated and Flared Tail Gas
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
H2S 0.03 6.13E-05 2.08E-03 8.38E-03 0.06 1.27E-04 4.31E-03 0.02
SO2 1.32 0.00 0.19 0.77 2.73 0.01 0.40 1.60
CO2 8509.33 19.38 852.76 3428.08 17588.69 40.06 640.96 2576.65
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Tail Gas Information
Average Flow Rates Maximum Flow Rates
After Flare (Scenario 1b)
Average Flow Rates Maximum Flow Rates
Before Flare (Scenario 1a)
Constituent
Constituent
GreenGasUSA 8/9/2024 Page 4 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Flaring Emissions - Scenario 1b
Table B-12. Treated Tail Gas Flaring Parameters
Annual Operation 8040 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrAverage Enrichment Gas Flow 3,600 scf/hr
Maximum Enrichment Gas Flow 6,720 scf/hrAverage Methane Gas Flow from
Tail Gas Stream2 945.48 scf/hr
Average Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Tail Gas Stream2 1954.30 scf/hr
Maximum Total Natural Gas Flow 8774.30 scf/hr
Natural Gas Higher Heating Value
(HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-13. Treated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual
Emissions (tpy)
Hourly
Emissions4
(lb/hr)
Annual
Emissions (tpy)NOX 0.1380 lb/MMBtu 6.54E-01 2.63E+00 1.24E+00 4.96E+00
CO 0.31 lb/MMBtu 1.47E+00 5.90 2.77E+00 11.15
VOC 0.66 lb/MMBtu 3.13E+00 12.57 5.91E+00 23.75PM7.60 lb/MMscf 3.53E-02 1.42E-01 6.67E-02 2.68E-01PM (con)5.70 lb/MMscf 2.65E-02 1.06E-01 5.00E-02 2.01E-01
PM (fil)1.90 lb/MMscf 8.83E-03 3.55E-02 1.67E-02 6.70E-02
SO2 0.60 lb/MMscf 2.79E-03 1.12E-02 5.26E-03 2.12E-02
CO25 119316.82 lb/MMscf 5.54E+02 2.23E+03 1.05E+03 4.21E+03
CH45 2.25 lb/MMscf 1.04E-02 4.20E-02 1.97E-02 7.93E-02
N2O5 0.22 lb/MMscf 1.04E-03 4.20E-03 1.97E-03 7.93E-03
CO2e6 119440.05 lb/MMscf 5.55E+02 2.23E+03 1.05E+03 4.21E+03
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-14. Treated Tail Gas Flaring HAP Emission Factors
Hourly
Emission
Annual
Emissions
Hourly
Emission
Annual
EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)
Benzene 2.10E-03 lb/MMscf 9.76E-06 3.92E-05 1.84E-05 7.41E-05
2-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.48E-07 2.11E-07 8.47E-073-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 2.99E-07 1.40E-07 5.64E-07Acenaphthene1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Acenaphthylene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.48E-08 2.11E-08 8.47E-08
Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 1.05E-08 4.23E-08Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 1.05E-08 4.23E-08
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 1.05E-08 4.23E-08
Dichlorobenzene 1.20E-03 lb/MMscf 5.57E-06 2.24E-05 1.05E-05 4.23E-05Fluoranthene3.00E-06 lb/MMscf 1.39E-08 5.60E-08 2.63E-08 1.06E-07
Fluorene 2.80E-06 lb/MMscf 1.30E-08 5.23E-08 2.46E-08 9.88E-08
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.40E-03 6.58E-04 2.65E-03Hexane1.8 lb/MMscf 8.36E-03 3.36E-02 1.58E-02 6.35E-02
Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.58E-08 6.35E-08Naphthalene6.10E-04 lb/MMscf 2.83E-06 1.14E-05 5.35E-06 2.15E-05
Phenanthrene 1.70E-05 lb/MMscf 7.90E-08 3.17E-07 1.49E-07 6.00E-07
Pyrene 5.00E-06 lb/MMscf 2.32E-08 9.34E-08 4.39E-08 1.76E-07
Toluene 3.40E-03 lb/MMscf 1.58E-05 6.35E-05 2.98E-05 1.20E-04
8.74E-03 3.52E-02 1.65E-02 6.64E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Total HAPs
Flare Information
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor1
GreenGasUSA 8/9/2024 Page 5 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Untreated and Flared Tail Gas - Scenario 2a
Table B-15. Untreated Tail Gas Parameters
Annual Operation 720 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (maximum)4.00 psig
Tail gas Temperature (actual)549.67 °R
Tail Gas Flow (average - std conditions) 1,2 9,455 scf/hr
Tail Gas Flow (maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 4,271 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 pisa
2. Conversion factors:
60 min/hr
Table B-16. Untreated Tail Gas Composition
H2S SO2 CH4 CO2
Concentration1,2 (%)0.427%0.000%10.00%90.00%
Average Flow Rate3 (scf/hr)40.38 0.00 945.48 8509.33
Maximum Flow Rate3 (scf/hr)83.46 0.00 1954.30 17588.69
Concentration1,2 (%)0.0085%0.419%-90.00%
Average Flow Rate3 (scf/hr)0.81 39.57 -8509.33Maximum Flow Rate3 (scf/hr)1.67 81.79 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted. See emissons from CH4 combustion on next page.
3. Flow Rate (scf/hr) = Concentration (%) * Raw Gas Flow (std conditions)(scf/hr)
Table B-17. Untreated Tail Gas Combusted Emissions
Volume Flow
Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume
Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 0.81 1.84E-03 0.06 0.02 1.67 3.80E-03 0.13 0.05
SO2 39.57 0.09 5.77 2.08 81.79 1.86E-01 11.92 4.29
CO2 8509.33 19.38 852.76 306.99 17588.69 4.01E+01 1762.64 634.55
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressur 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempatur 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
Average Flow Rates Maximum Flow Rates
Constituent
Tail Gas Information
Before Flare
After Flare
GreenGasUSA 8/9/2024 Page 6 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Untreated Tail Gas - Scenario 2a
Table B-18. Untreated Tail Gas Flaring Parameters
Annual Operation 720 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrEnrichment Gas Flow 3,600 scf/hr
Maximum Enrichment Gas Glow 6,720 scf/hrAverage Methane Gas Flow from Untreated
Tail Gas Stream2 945.48 scf/hrAverage Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Untreated Tail Gas Stream2 1954.30 scf/hr
Maximum Total Natural Gas Flow 8774.30 scf/hr
Natural Gas Higher Heating Value (HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-19. Untreated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual Emissions (tpy)
Hourly
Emissions4
(lb/hr)
Annual Emissions (tpy)
NOX 0.1380 lb/MMBtu 6.54E-01 2.35E-01 1.24E+00 4.45E-01CO 0.31 lb/MMBtu 1.47E+00 0.53 2.77E+00 1.00VOC 0.66 lb/MMBtu 3.13E+00 1.13 5.91E+00 2.13PM7.60 lb/MMscf 3.53E-02 1.27E-02 6.67E-02 2.40E-02PM (con)5.70 lb/MMscf 2.65E-02 0.01 5.00E-02 0.02PM (fil)1.90 lb/MMscf 8.83E-03 0.00 1.67E-02 0.01SO20.60 lb/MMscf 2.79E-03 1.00E-03 5.26E-03 1.90E-03
CO25 119316.82 lb/MMscf 5.54E+02 199.54 1.05E+03 3.77E+02
CH45 2.25 lb/MMscf 1.04E-02 3.76E-03 1.97E-02 7.10E-03
N2O5 0.22 lb/MMscf 1.04E-03 3.76E-04 1.97E-03 0.00
CO2e6 119440.05 lb/MMscf 5.55E+02 200 1.05E+03 377
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-20. Misc. Natural Gas HAP Emission Factors
Hourly Emission Annual Emissions Hourly Emission Annual EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)Benzene 2.10E-03 lb/MMscf 9.76E-06 3.51E-06 1.84E-05 6.63E-06
2-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.01E-08 2.11E-07 7.58E-083-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 2.68E-08 1.40E-07 5.05E-08
Acenaphthene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Acenaphthylene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.01E-09 2.11E-08 7.58E-09
Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 1.05E-08 3.79E-09
Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 1.05E-08 3.79E-09
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 1.05E-08 3.79E-09
Dichlorobenzene 1.20E-03 lb/MMscf 5.57E-06 2.01E-06 1.05E-05 3.79E-06
Fluoranthene 3.00E-06 lb/MMscf 1.39E-08 5.02E-09 2.63E-08 9.48E-09
Fluorene 2.80E-06 lb/MMscf 1.30E-08 4.68E-09 2.46E-08 8.84E-09
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.25E-04 6.58E-04 2.37E-04
Hexane 1.8 lb/MMscf 8.36E-03 3.01E-03 1.58E-02 5.69E-03
Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.58E-08 5.69E-09
Naphthalene 6.10E-04 lb/MMscf 2.83E-06 1.02E-06 5.35E-06 1.93E-06
Phenanthrene 1.70E-05 lb/MMscf 7.90E-08 2.84E-08 1.49E-07 5.37E-08Pyrene5.00E-06 lb/MMscf 2.32E-08 8.36E-09 4.39E-08 1.58E-08
Toluene 3.40E-03 lb/MMscf 1.58E-05 5.69E-06 2.98E-05 1.07E-05
8.74E-03 3.15E-03 1.65E-02 5.95E-03
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Total HAPs
Flare Information
Pollutant Emission Factor1
Average Natural Gas Flow
GreenGasUSA 8/9/2024 Page 7 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Raw Gas - Scenario 2b
Table B-21. Raw Gas Parameters
Annual Operation 720 hrs/yr
Average Raw Gas Flow 410 acf/minMaximum Raw Gas Flow 775 acf/min
Raw Gas Pressure 1.00 psig
Raw Gas Temperature (actual)539.67 °R
Average Raw Gas Flow (std conditions) 1,2 25,554 scf/hr
Maximum Raw Gas Flow (std conditions) 1,3 48,302 scf/hr
H2S Concentration 1,500 ppmv
1. Raw Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 pisa
2. Conversion factors:
60 min/hr
Table B-22. Raw Gas Composition
H2S SO2 CH4 CO2
Concentration1,2 (%)0.150%0.000%70.00%30.00%
Average Flow Rate3 (scf/hr)38.33 0.00 17887.49 7666.07Maximum Flow Rate3 (scf/hr)72.45 0.00 33811.72 14490.74
Concentration1,2 (%)0.0030%0.147%-30.00%
Average Flow Rate3 (scf/hr)0.77 37.56 -7666.07
Maximum Flow Rate3 (scf/hr)1.45 71.00 -14490.74
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
3. Flow Rate (scf/hr) = Concentration (%) * Raw Gas Flow (std conditions)(scf/hr)
Table B-23. Emissions from Raw Gas Combustion
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
H2S 0.77 1.75E-03 0.06 0.02 1.45 3.30E-03 0.11 0.04
SO2 37.56 0.09 5.48 1.97 71.00 0.16 10.35 3.73
CO2 7666.07 17.46 768.25 276.57 14490.74 33.00 1452.18 522.78
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressur 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempatu 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
Average Flow Rates Maximum Flow Rates
Constituent
Raw Gas Information
Before Flare
After Flare
GreenGasUSA 8/9/2024 Page 8 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Raw Gas - Scenario 2b
Table B-24. Natural Gas Parameters
Annual Operation 720 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrAverage Methane Gas Flow from Raw Gas
Stream2 17887.49 scf/hrAverage Total Natural Gas Flow 17987.49 scf/hrMaximum Methane Gas Flow from Raw
Gas Stream2 33811.72 scf/hrMaximum Total Natural Gas Flow 33911.72 scf/hr
Natural Gas Higher Heating Value (HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of raw gas is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-25. Emissions from Natural Gas
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
NOX 0.1380 lb/MMBtu 2.53E+00 0.91 4.77E+00 1.72CO 0.31 lb/MMBtu 5.69E+00 2.05 1.07E+01 3.86VOC 0.66 lb/MMBtu 1.21E+01 4.36 2.28E+01 8.22
PM 7.60 lb/MMscf 1.37E-01 0.05 2.58E-01 0.09PM (con)5.70 lb/MMscf 1.03E-01 0.04 1.93E-01 0.07PM (fil)1.90 lb/MMscf 3.42E-02 0.01 6.44E-02 0.02
SO2 0.60 lb/MMscf 1.08E-02 0.00 2.03E-02 0.01
CO25 119316.82 lb/MMscf 2.15E+03 773 4.05E+03 1,457
CH45 2.25 lb/MMscf 4.04E-02 0.01 7.63E-02 0.03
N2O5 0.22 lb/MMscf 4.04E-03 0.00 7.63E-03 0.00
CO2e6 119440.05 lb/MMscf 2.15E+03 773 4.05E+03 1,458
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-26. Misc. Natural Gas HAP Emission Factors
Hourly Annual Hourly Annual Value Unit (lb/hr)(tpy)(lb/hr)(tpy)
Benzene 2.10E-03 lb/MMscf 3.78E-05 1.36E-05 7.12E-05 2.56E-052-Methylnaphthalene 2.40E-05 lb/MMscf 4.32E-07 1.55E-07 8.14E-07 2.93E-07
3-Methylcholanthrene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 2.88E-07 1.04E-07 5.43E-07 1.95E-07Acenaphthene1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Acenaphthylene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Anthracene 2.40E-06 lb/MMscf 4.32E-08 1.55E-08 8.14E-08 2.93E-08Benz(a)anthracene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Benzo(a)pyrene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08Benzo(b)fluoranthene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Chrysene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Dichlorobenzene 1.20E-03 lb/MMscf 2.16E-05 7.77E-06 4.07E-05 1.46E-05
Fluoranthene 3.00E-06 lb/MMscf 5.40E-08 1.94E-08 1.02E-07 3.66E-08
Fluorene 2.80E-06 lb/MMscf 5.04E-08 1.81E-08 9.50E-08 3.42E-08
Formaldehyde 7.50E-02 lb/MMscf 1.35E-03 4.86E-04 2.54E-03 9.16E-04
Hexane 1.8 lb/MMscf 3.24E-02 1.17E-02 6.10E-02 2.20E-02Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Naphthalene 6.10E-04 lb/MMscf 1.10E-05 3.95E-06 2.07E-05 7.45E-06
Phenanthrene 1.70E-05 lb/MMscf 3.06E-07 1.10E-07 5.76E-07 2.08E-07Pyrene5.00E-06 lb/MMscf 8.99E-08 3.24E-08 1.70E-07 6.10E-08
Toluene 3.40E-03 lb/MMscf 6.12E-05 2.20E-05 1.15E-04 4.15E-053.39E-02 1.22E-02 6.38E-02 2.30E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Total HAPs
Flare Information
Pollutant Natural Gas1
Average Natural Gas Flow
GreenGasUSA 8/9/2024 Page 9 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Fugitive emissions
Table B-27. Fugitive Emission Factors Table B-28. Speciated Gas Components
Component wt%1
H2S wt%0.15%
(lb/hr/source)CO2 wt%30.00%
Valves - Gas 0.01320 30 CH4 wt%70.00%
Flanges - Gas 0.00390 60 1. Raw gas composition used for fugitive calculations
Compressor Seals - Gas 0.50270 3
Relief Valves - Gas 0.22930 15
Sampling Connection - Gas 0.03300 3
Table B-29. Emission Rates for CO2 and CH4
(lb/hr)(tpy)(lb/hr)(tpy)(lb/hr)(tpy)Valves - Gas 0.12 0.52 0.28 1.21 7.05 30.87Flanges - Gas 0.07 0.31 0.16 0.72 4.17 18.24Compressor Seals - Gas 0.45 1.98 1.06 4.62 26.84 117.58Relief Valves - Gas 1.03 4.52 2.41 10.55 61.22 268.16
Other - Gas 0.03 0.13 0.07 0.30 1.76 7.72
Total 1.70 7.46 3.97 17.40 101.04 442.57
1. Hours of operations:8760
2. Global Warming Potential of CH4 from 40 CFR 98 Table A-1 25
Table B-30. Emission Rate for H2S
(lb/hr)(tpy)Valves - Gas 5.94E-04 2.60E-03Flanges - Gas 3.51E-04 1.54E-03Compressor Seals - Gas 2.26E-03 9.91E-03Relief Valves - Gas 5.16E-03 0.02
Other - Gas 1.49E-04 6.50E-04
Total 0.01 0.04
H2S Emission RateEquipment Type
Equipment Type CO2e Emission Rate1,2
Equipment Type
Uncontrolled
Emission
Factor1 Source
Count
1. Factors are from TCEQ Air Permit Technical Guidance for Chemical Sources: Fugitive Guidance. Emission Factors - Oil and Gas Production
Operations, June 2018.
CO2 Emission Rate CH4 Emission Rate
GreenGasUSA 8/9/2024 Page 10 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-1. GreenGasUSA Potential To Emit Annual Emissions Summary
NOX NO2 CO PM10 PM2.5 SO2 VOC CO2e H2S Total HAPs
1a Treated Tail Gas Emitted -------14243.16 0.87 0.00
1b Treated Tail Gas Combusted 4.96 4.96 11.15 0.27 0.27 1.62 23.75 11298.76 0.02 0.072aUntreated Tail Gas Combusted 0.44 0.44 1.00 0.02 0.02 4.29 2.13 1011.83 0.05 0.012bRaw Gas Combusted 1.72 1.72 3.86 0.09 0.09 3.73 8.22 1980.93 0.04 0.02-------442.57 0.04 0.00
6.68 6.68 15.01 0.36 0.36 5.91 31.96 16666.66 0.95 0.09
100 100 250 250 100 100 250 100,000 -10/25NoNoNoNoNoNoNoNo-No
40 40 100 15 10 40 ----See HAPS
Summary
See HAPS
SummaryNoNoNoNoNoNoNoNoNoNo
1. Facility wide PTE is calculated by summing the maximum of scenarios 1a and 1b with the maximum of scenarios 2a and 2b, including fugitive emissions
2. Major source thresholds are defined by 40 CFR section 52.21(b)(1).
3. Modeling Limit is stated in UDAQ Emissions Impact Assessment Guidelines under Table 1: Total Controlled Emission Rates for New Sources or Emissions Increase.
Modeling Limits3
Threshold Exceeded?
Scenario Description
Fugitives
Scenario Number
Facility Wide PTE1
Scenario
Normal (VAV operational)
Emergency/Maintenance (VAV not operational)
Potential To Emit (tpy)
Major Source Thresholds2
Threshold Exceeded?
GreenGasUSA 8/9/2024 Page 1 of 2
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-2. Maximum Potential HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b2-Methylnaphthalene -2.11E-07 2.11E-07 8.14E-07 8.14E-07 --No3-Methylcholanthrene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
7,12-Dimethylbenz(a)anthracene -1.40E-07 1.40E-07 5.43E-07 5.43E-07 --No
Acenaphthene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Acenaphthylene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Anthracene -2.11E-08 2.11E-08 8.14E-08 8.14E-08 --NoBenz(a)anthracene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoBenzene-1.84E-05 1.84E-05 7.12E-05 7.12E-05 0.31627362 No
Benzo(a)pyrene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --No
Benzo(b)fluoranthene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --No
Benzo(g,h,i)perylene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --No
Chrysene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoDibenzo(a,h) anthracene -1.05E-08 1.05E-08 4.07E-08 4.07E-08 --NoDichlorobenzene-1.05E-05 1.05E-05 4.07E-05 4.07E-05 --No
Fluoranthene -2.63E-08 2.63E-08 1.02E-07 1.02E-07 --No
Fluorene -2.46E-08 2.46E-08 9.50E-08 9.50E-08 --No
Formaldehyde -6.58E-04 6.58E-04 2.54E-03 0.0025 0.0567438 No
Hexane -1.58E-02 1.58E-02 6.10E-02 6.10E-02 34.8949693 NoIndeno(1,2,3-cd)pyrene -1.58E-08 1.58E-08 6.10E-08 6.10E-08 --NoNaphthalene-5.35E-06 5.35E-06 2.07E-05 2.07E-05 10.3810307 NoPhenanthrene-1.49E-07 1.49E-07 5.76E-07 5.76E-07 --No
Pyrene -4.39E-08 4.39E-08 1.70E-07 1.70E-07 --No
Toluene -2.98E-05 2.98E-05 1.15E-04 1.15E-04 14.9216687 No
H2S 0.2154 0.0043 0.1293 0.1122 0.13 0.2760 No
1. The Emission Threshold Value (ETV) assumes <50 m distance to the fenceline and vertically unrestricted releases.
Modeling
Required?Project Hourly Emissions (lb/hr)Pollutant Maximum
Emissions (lb/hr)ETV1
(lb/hr)
GreenGasUSA 8/9/2024 Page 2 of 2
UTAN Utah Division of Air Quality
New source Review Section
Ownership Change/Company Name Change Notification
The following information is necessary before the Division will be able to make the name
change you have requested.Please return this document within 30 days of receipt.
Please be aware that all records associated with this company will change to the new name unless you specifically
indicate otherwise.The fee assessed for making thesechanges is authorized by the legislature for the actual time spent
by the reviewer.
Note:If this namechange is theresult ofasaleoracquisition,both the buyer &the seller mustsign this document
as proofof the closure of theagreement.
ReasonforOwnershipChange/CompanyNameChange Crentny seqerat
CompanyName
Current
GaUsA Hyrum uc
Parent Company:
CompanyAddress
Current
4237 Sprull Ae,Suite 202
Noth Charerton,5c 244os
Approval Orders Afected and SitesForEachApprovalOrder
Approval Order #(DAQE-ANXXXXXXXXXX-Xx)
Entities
Previous
GreenChasUSA
Parent Company:
Previous
4400 o'Hear Ave Sute (00
Nostn Chaieshn,SC 2y oS
Site Name &Address (for each Approval Order)
The undersigned,asan authorized representative of the company,acknowledges that the above information is correct,
and requests that the company name change be made in all Air Quality records.
PresentOwner CrenhasysA
Signake
Scot Wiljon
Name (please print)
CoDTitle
Cosy Mwakami
Contact Name (Pleaseprint)
(843)b4u.4923
Phone Number
Casey.huralamie re
E-mail
SECTIONFonns\NameChange.doc Revised 5/16/11
PreviousOwner nrencrasUsA
Signature
Sott Nilsea
Name(pleaseprint)
Coo
Title
Return this form to:
State ofUtah
Division of Air Quality
Attn:NSR-Ownership/Name Change Notification
195 North 1950 West
as usaom PO Box 144820
Salt Lake City,Utah 84114-4820

UTAH DIVISION OF AIR QUALITY – NOTICE
OF INTENT
GreenGasUSA / RNG Facility

New Approval Order

Prepared by:
TRINITY CONSULTANTS
4525 Wasatch Boulevard
Suite 200
Salt Lake City, Utah 84104
[phone]

Submitted on Behalf of:
GreenGasUSA
August 2024

GreenGasUSA / RNG Facility Permit Application Trinity Consultants
TABLE OF CONTENTS
TABLE OF CONTENTS
1. EXECUTIVE SUMMARY 1-1
2. GENERAL INFORMATION 2-2
Source Identification Summary ......................................................................................... 2-2
2.1 Area Designation ....................................................................................................... 2-2
2.2 Source Size Determination ........................................................................................ 2-2
2.3 Single Stationary Source Designation ....................................................................... 2-3
2.4 Notice of Intent Forms .............................................................................................. 2-4
2.5 Notice of Intent Fees ................................................................................................ 2-4
3. DESCRIPTION OF PROJECT AND PROCESS 3-1
3.1 Proposed RNG Facility ............................................................................................... 3-1
3.1.1 Anerobic Digestor.................................................................................................... 3-1
3.1.2 Oxygen Injection Skid and Feed Gas Compression ........... Error! Bookmark not defined.
3.1.3 Vacuum Adsorption Vessel ....................................................................................... 3-2
3.1.4 Molecular Gate™ PSA .............................................................................................. 3-2
3.1.5 Flare ...................................................................................................................... 3-2
4. EMISSION CALCULATION METHODOLOGY 4-1 4.1 Operating Scenarios .................................................................................................. 4-1 4.2 Proposed Calculation Methodology ........................................................................... 4-1
4.2.1 H2S, SO2, CO2, and CH4 Emissions ............................................................................ 4-1
4.2.2 Combustion Pollutants ............................................................................................. 4-2
4.2.3 GHG Emissions ....................................................................................................... 4-3
4.2.4 HAP Emissions ........................................................................................................ 4-4
5. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS 5-1
5.1 Tail Gas H2S Emissions .............................................................................................. 5-1
5.1.1 Step 1 - Identify All Control Technologies .................................................................. 5-1
5.1.2 Step 2 – Eliminate Technically Infeasible Control Options ............................................ 5-1
Caustic Scrubber ................................................................................................................ 5-1
Dry Techniques .................................................................................................................. 5-2
Iron Removal Methods ...................................................................................................... 5-2
Biological Methods ............................................................................................................ 5-3
Flare/Thermal Oxidation ................................................................................................... 5-3
5.1.3 Steps 3- Rank Remaining Technologies by Control Effectiveness .................................. 5-3
5.1.4 Step 5 – Select BACT ............................................................................................... 5-4
5.2 Flaring Emissions ...................................................................................................... 5-4
5.3 Equipment Leaks ....................................................................................................... 5-4
6. EMISSION IMPACT ANALYSIS 6-1
7. NONATTAINMENT/MAINTENANCE AREAS - OFFSETTING 7-1 Offset Applicability ............................................................................................................ 7-1
PM2.5 Offsets ..................................................................................................................... 7-1
7.1.1 PM10 Offsets ........................................................................................................... 7-1
GreenGasUSA / RNG Facility Permit Application Trinity Consultants i
7.1.2 Ozone Offsets ......................................................................................................... 7-1
8. APPLICABLE REGULATIONS 8-1
UDAQ Air Quality Rules ...................................................................................................... 8-1
8.1.1 UAC R307-101 General Requirements ....................................................................... 8-4
8.1.2 UAC R307-107 General Requirements: Breakdowns .................................................... 8-5
8.1.3 UAC R307-201 Emission Standards: General Emission Standards ................................. 8-5
8.1.4 UAC R307-410-8 Permits: Permit New and Modified Sources – Approval Order .............. 8-5
8.1.5 UAC R307-414 Permits: Fees for Approval Orders ....................................................... 8-6
8.2 New Source Performance Standards ......................................................................... 8-6
8.2.1 40 CFR 60 Subpart A – General Provisions ................................................................. 8-6
8.2.2 40 CFR 60 OOOOa – Crude Oil and Natural Gas Facilities ............................................ 8-6
8.2.3 40 CFR 60 OOOOb – Standards of Performance for Crude Oil and Natural Gas .............. 8-6
8.3 National Emissions Standards for Hazardous Air Pollutants ...................................... 8-6
8.3.1 40 CFR 61 – National Emission Standards for Hazardous Air Pollutants ......................... 8-6
8.3.2 40 CFR 63 Subpart A – General Provisions ................................................................. 8-7
8.3.3 40 CFR 63 Subpart HHH – Natural Gas Transmission and Storage Facilities ................... 8-7
8.4 40 CFR Part 98 Greenhouse Gas Emissions ............................................................... 8-7
APPENDIX A. FORMS A
APPENDIX B. EMISSION CALCULATION B

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 1-1
1. EXECUTIVE SUMMARY
GreenGasUSA (GreenGas) is proposing to construct a Renewable Natural Gas (RNG) Facility which will treat
the biogas (raw gas) from anaerobic digestors and deliver the treated gas to a natural gas pipeline
distribution system. The feed stream for the digestor will be waste from Swift Beef Company, Incorporated
(Swift Beef). Swift Beef owns and operates a beef processing plant located in the city of Hyrum, Utah.1
While GreenGas will be located on Swift Beef’s property, with this application GreenGas is requesting that
they be considered a separate stationary source and granted an Approval Order air permit.

The RNG Facility will be located in Cache County, which is currently in attainment with the National Ambient
Air Quality Standards (NAAQS) for all criteria pollutants. Previously, portions of Cache County were
designated as moderate nonattainment for particulate matter (PM) with an aerodynamic diameter of 2.5
microns or less (PM2.5), but on June 18, 2021, the Logan-Cache moderate nonattainment area was
redesignated to attainment status. However, the State Implementation Plan (SIP) remains in effect to
ensure the area’s continued compliance with air quality standards. As such, the major source thresholds for
PM2.5 and its precursors (nitrogen oxides (NOX), sulfur dioxide (SO2), volatile organic compounds (VOCs),
and ammonia (NH3)) in this location are 100 tons per year (tpy).2
This Notice of Intent (NOI) air quality application is being submitted in accordance with the Utah Division of
Air Quality (UDAQ) rules, Utah Administrative Code (UAC) R307-401, and includes all supporting
documentation in order to obtain authorization for the changes specified above. This NOI air permit
application includes, but is not limited to:

► NOI Air Permit Application Forms and Fees;
► Process Description;
► Potential to Emit (PTE) Calculations;
► Best Available Control Technology (BACT) Analysis;
► Applicable Requirements; and
► Emission Impact Analysis Applicability.

1 The Swift Beef Plant operates under approval order (AO) DAQE-AN100510021-23 issued by the Utah Department of Air Quality (UDAQ) on June 9, 2023. 2 40 CFR 51.165(a)(1)(iv)(A), definition of a major stationary source.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 2-2
2. GENERAL INFORMATION
The following section contains the information requested under the “Source Identification Information”
section of UDAQ’s Form 1 Notice of Intent (NOI) Application Checklist.
Source Identification Summary
► Company Name: GreenGasUSA
► Address: 410 North 200 West, Hyrum, Utah
► County: Cache County
► UTM Coordinates: 428,370 m E, 4,610,901 m N, Zone 12
► Primary SIC Code: 1311 – Crude Petroleum and Natural Gas
► Current AO: None

All correspondence regarding this submission should be addressed to:

Casey Murakami
Environmental, Health, and Safety Manager
4900 O’Hear Ave, Suite 100
North Charleston, SC 29405
Phone: [phone]
Email: [e-mail]

2.1 Area Designation
The proposed RNG Facility is located within an area of Cache County that is classified as in attainment for all
pollutants with exception to PM2.5 for which it is classified as a PM2.5 Maintenance area of the National
Ambient Air Quality Standards (NAAQS).
2.2 Source Size Determination
As presented in Appendix B, Table B-1, site-wide emissions at the RNG Facility are less than the major
source thresholds (MST) for all criteria pollutants. Additionally, the RNG facility is not under the listed 28
sources detailed in 40 CFR 52.21. This RNG Facility will be designated as a minor source under New Source
Review (NSR) and is therefore not a major source under the Prevention of Significant Deterioration (PSD)
program.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 2-3
2.3 Single Stationary Source Designation
Because the proposed RNG facility will be collocated with the Swift Beef Plant, GreenGas has evaluated the
need to consider the Swift Beef Plant and RNG facility as a single source. EPA defines a stationary source in
40 CFR 52.21(b)(5), as follows:

Any building, structure, facility, or installation which emits or may emit a regulated NSR pollutant.

40 CFR 52.21(b)(6) defines “building, structure, facility, or installation” as:

All of the pollutant-emitting activities which belong to the same industrial grouping, are located on
one or more contiguous or adjacent properties, and are under the control of the same person (or
persons under common control) except the activities of any vessel. Pollutant-emitting activities shall
be considered as part of the same industrial grouping if they belong to the same “Major Group” (i.e.,
which have the same first two digit code) as described in the Standard Industrial Classification
Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock
numbers 4101-0066 and 003-005-00716-0, respectively).

Consistent with this definition and guidance published by EPA, three items are important in the
determination of a single source: (1) same industrial grouping, (2) contiguous or adjacent properties, and
(3) common control.3
2.3.1.1 Same Industrial Grouping
The preamble to the PSD regulations, issued on August 7, 1980, clarifies the “industrial grouping” aspect of
the definition:

Each source is to be classified according to its primary activity, which is determined by its principal
product or group of products produced or distributed, or services rendered. Thus, one source
classification encompasses both primary and support facilities, even when the latter includes units
with a different two digit SIC code. Support facilities are typically those which convey, store or
otherwise assist in the production of the principal product. Where a single unit is used to support
two otherwise distinct sets of activities, the unit is to be included within the source which relies most
heavily on its support.

The Primary NAICS code for the RNG Facility is 211130 – Natural Gas Extraction, and the SIC code is 1311 –
Crude Petroleum and Natural Gas. The Swift Beef Plant has the Primary NAICS code of 311613 (Rendering
and Meat Byproduct Processing), and the SIC code is 2011 (Meat Packing Plant). The SIC and NAICS codes
for the facilities are different. Therefore, they are not of the same industrial grouping, and the criteria for
“same industrial grouping” is not met.
2.3.1.2 Contiguous or Adjacent Properties
Per EPA guidance, “contiguous property” means:

3 Memo dated April 30, 2018, from William L. Wehrum (EPA, Assistant Administrator) to Patrick McDonnel (Secretary of the Pennsylvania Department of Environmental Protection), titled “Meadowbrook Energy and Keystone Landfill Common Control Analysis”. Accessed at: https://www.epa.gov/sites/default/files/2018-05/documents/meadowbrook_2018.pdf.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 2-4
Property that is adjoining. Public rights-of-way (e.g., railroads, highways) do not prevent property
from being considered contiguous. Property connected only by rights-of-way are not considered
contiguous (e.g., two plants with a connecting pipeline).

The RNG Facility will be located within a leased section of the existing Swift Beef Plant property. Therefore,
the properties are considered contiguous, and criteria for “contiguous or adjacent properties” is met.
2.3.1.3 Common Control
The intent of EPA in the use of the term “common control” is “guided by the general definition of control
used by the Security and Exchange Commission (SEC)”. Specifically, control can be considered “common” if
they are considered either of the following three types: (1) common ownership (i.e., the same parent
company), (2) contractual requirements, or (3) dependence.

The RNG Facility at the Swift Beef Plant will not be under common ownership. The RNG Facility will be
owned and operated by GreenGasUSA and the Swift Beef Plant will continue to be operated by Swift Beef
Company.
2.3.1.4 Conclusion
The RNG Facility at the Swift Beef Plant will be located on contiguous or adjacent properties but will not be
under common control nor be in the same SIC Major Group. Therefore, the GreenGas RNG facility will be a
separate stationary source.
2.4 Notice of Intent Forms
The following UDAQ forms have been included with this NOI air permit application:

► Form 1 – Notice of Intent (NOI) Application Checklist
► Form 2 – Company Information/Notice of Intent (NOI)
► Form 3 – Process Information
► Form 4 - Flare
► Form 5 – Emissions Information Criteria/GHGs/HAPs
2.5 Notice of Intent Fees
GreenGas will use the UDAQ’s Payment Portal to prepay the following UDAQ NOI air permit application fees
associated with this submittal:

“Application Filing Fee” for the “New Minor Source or Minor Modification at Minor or Major Source” category
= $575
“Application Review Fee” for the “New Minor Source or Minor Modification at Minor or Major Source”
category in maintenance or non-attainment areas = $2,500

Total UDAQ fees = $3,075

GreenGas understands that the total permit review fee is based on the total actual time spent by UDAQ staff
processing this NOI air permit application. Upon issuance of the AO, if the total review time is more than 20
standard hours, UDAQ will invoice GreenGas at $125 per hour for the additional time above 20 standard
hours.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 3-1
3. DESCRIPTION OF PROJECT AND PROCESS
GreenGas is proposing to construct, operate and maintain a new RNG Facility to collect gas generated at the
Swift Beef Plant, treat the gas to meet natural gas pipeline standards, and inject the treated gas into a
natural gas pipeline for delivery to customers.
3.1 Proposed RNG Facility
This section describes the process areas of the proposed RNG Facility co-located at the Swift Beef Plant. The
RNG Facility will consist of an anaerobic digestor, an oxygen injection skid, a hydrogen sulfide (H2S) vacuum
adsorption vessel (VAV), a molecular gate (Molegate) pressure swing adsorption (PSA) skid, and a stack
with a flare.

Figure 3-1 depicts the process flow diagram of the proposed RNG facility, with all the associated equipment.

Figure 3-1 Process Flow Diagram

3.1.1 Anerobic Digestor
Untreated gas from the Swift Beef Plant’s rendering process is fed into a lagoon equipped with anerobic
digestors. During anaerobic digestion, microorganisms break down (eat) organic materials in the absence of
air (or oxygen). This process generates large amounts of methane as the organics in the waste decompose.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 3-2
3.1.2 Vacuum Adsorption Vessel
The raw gas will be sent to a Vacuum Adsorption Vessell (VAV) which houses iron substrate that is used to
controls H2S content. Further description of this control technology can be found in the BACT section.
Following treatment, the concentration of H2S in the gas will be 50 ppm or less.
3.1.3 Molecular Gate™ PSA
The gas cleanup system uses a PSA technology that features a Molecular Gate PSA to remove CO2, H2S, and
H2O in a single step. PSA technology works through a chemical separation process in which a mixture of
gases is passed through a bed of adsorbent media at high pressure. Under high pressure, the specific gases
will be selectively adsorbed onto the surface and pores of the adsorbent media. The gases are removed
from the media by “swinging” the media to low pressure.

Methane, N2 and O2 pass through the molecular gate as “product gas”. Vacuum compression is used to
regenerate the PSA media and remove contaminants (CO2, H2S, and H2O) which are known as PSA “tail
gas”. Tail gas from the Molecular Gate PSA will either be sent to the flare stack for release to ambient air
without combustion or combusted to ensure odors from the process remain low.
3.1.4 Flare
The flare will consist of one skid mounted, self-supporting flare stack, utility flare tip, pilot with Type K
thermocouple, and an automatic ignition/monitoring system.

When in normal operation, the flare will not be used; tail gas will exit the stack without combusting. When
treating tail gas, the flare will utilize natural gas for a pilot flame and additional natural gas as enrichment
gas to ensure combustion. When treating raw gas, the methane content of the raw gas is high enough
where a pilot flame is sufficient for combustion without the addition of enrichment gas.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 4-1
4. EMISSION CALCULATION METHODOLOGY
This section details the methodology used to calculate controlled and uncontrolled emissions for criteria
pollutants, greenhouse gases (GHGs), and hazardous air pollutants (HAPs) associated with each new unit
and its associated fugitives as regulated by R307-401-5(2)(b). Detailed emission calculation tables are
included in Appendix B. Additionally, a comparison to MSTs is conducted.
4.1 Operating Scenarios
GreenGas is proposing to operate under several operating scenarios. Each of these scenarios utilizes a
similar emission calculation methodology but results in varying levels of emissions based on the sulfur
content and supplemental gas required to ensure complete combustion when flaring. The scenarios are
labeled as follows and are depicted in Figure 4-1:

1. Normal Operation Scenarios
• 1a. Tail gas is treated by the VAV and is emitted directly without flaring
• 1b. Tail gas is treated by the VAV and is flared

2. Emergency/Maintenance Operation Scenarios
• 2a. Tail gas is not treated by the VAV and is flared
• 2b. Raw gas is not treated and is flared

Figure 4-1 Emissions Flow Diagram

For the purpose of annual PTE calculation, up to 30 days/year of emergency/maintenance operation
scenarios were accounted for when the VAV may not be operational, and normal operation scenarios were
assumed to occur for the rest of the year. Both normal and emergency operations will have emissions that
include H2S and Greenhouse Gases (GHG). Combustion pollutants result from the natural gas in the pilot
flame and include NOX, CO, VOC, PM, SO2, GHGs, and HAPs. Detailed emission calculations are presented in
Appendix B.
4.2 Proposed Calculation Methodology
4.2.1 H2S, SO2, CO2, and CH4 Emissions
Emissions of H2S, SO2, CO2, and CH4 are dependent on the concentration of these components within the
raw gas produced by the anerobic digestor or tail gas formed by the Molegate. Both raw gas and tail gas are measured as a volumetric flow rate (𝑉𝑉̇) and the pollutant emission rate is determined by multiplying the

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 4-2
volumetric flow rate by the pollutant concentration to obtain a volumetric flow rate of that particular
pollutant as seen below:
𝑉𝑉 ̇𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝�𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�=𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑝𝑝 (%)× 𝑇𝑇𝑝𝑝𝐶𝐶𝑝𝑝/𝑅𝑅𝑝𝑝𝑅𝑅 𝑔𝑔𝑝𝑝𝑠𝑠 𝑠𝑠𝑝𝑝𝑝𝑝𝑅𝑅 �𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�

For scenarios which include flaring (Scenarios 1b, 2a and 2b) the H2S, CO2, and CH4 pollutant specific
emission rate also accounts for the destruction efficiency of the flare as seen in the equation below:
𝑉𝑉 ̇𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝�𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�=�𝑃𝑃𝑟𝑟𝐶𝐶 𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟𝐶𝐶 𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑝𝑝 (%)−�𝑃𝑃𝑟𝑟𝐶𝐶 𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟𝐶𝐶 𝑠𝑠𝑝𝑝𝑝𝑝𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑝𝑝 (%)× 𝐶𝐶𝑝𝑝𝑝𝑝𝐶𝐶𝐶𝐶𝑟𝑟𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝(%)�� × 𝑇𝑇𝑝𝑝𝐶𝐶𝑝𝑝/𝑅𝑅𝑝𝑝𝑅𝑅 𝑔𝑔𝑝𝑝𝑠𝑠 𝑠𝑠𝑝𝑝𝑝𝑝𝑅𝑅 �𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�

SO2 emissions are primarily the result of combusting H2S and thus the volumetric emission rate is based on
the H2S concentration and calculated as follows:
𝑉𝑉:̇𝑆𝑆𝑆𝑆2 �𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�=��𝐻𝐻2𝑆𝑆 𝑃𝑃𝑟𝑟𝐶𝐶 𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟𝐶𝐶 𝑠𝑠𝑝𝑝𝑝𝑝𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑝𝑝 (%)× 𝐶𝐶𝑝𝑝𝑝𝑝𝐶𝐶𝐶𝐶𝑟𝑟𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝(%)�� × 𝑅𝑅𝑝𝑝𝑅𝑅 𝑔𝑔𝑝𝑝𝑠𝑠 𝑠𝑠𝑝𝑝𝑝𝑝𝑅𝑅 �𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�

For all operating scenarios, volumetric emissions of SO2, H2S, CO2, and CH4 are converted to mass emission
rates (𝑚𝑚) ̇using the ideal gas law:
𝑚𝑚 ̇�𝑝𝑝𝑙𝑙ℎ𝑟𝑟�=(𝑀𝑀𝑀𝑀)𝑃𝑃𝑉𝑉̇𝑅𝑅𝑇𝑇

Where:
MW: molecular weight (lb/lb-mol)
P: standard pressure = 14.7 psia
V: volumetric flow rate (scf/hr)
R: gas constant = 10.73 𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝∙𝑓𝑓𝑡𝑡3𝑙𝑙𝑙𝑙−𝑚𝑚𝑚𝑚𝑙𝑙∙°𝑅𝑅
T: standard temperature = 519.67 °𝑅𝑅

4.2.2 Combustion Pollutants
For operations that include flaring, pollutants arising from natural gas combustion will be emitted. The
combustion pollutants include NOx, CO, VOC, PM and SO2. Hourly emissions were determined using
emission factors, the natural gas higher heating value (HHV) per AP-42 Chapter 1.4, and the gas flow rate.
The gas flow is calculated as a summation of all the natural gas flows in that specific process, as follows:
𝑇𝑇𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝑁𝑁𝑝𝑝𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝 𝐺𝐺𝑝𝑝𝑠𝑠 𝐹𝐹𝑝𝑝𝑝𝑝𝑅𝑅 �𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�=𝐸𝐸𝑝𝑝𝑟𝑟𝐶𝐶𝑠𝑠ℎ𝑚𝑚𝐶𝐶𝑝𝑝𝑝𝑝 𝐺𝐺𝑝𝑝𝑠𝑠 𝐹𝐹𝑝𝑝𝑝𝑝𝑅𝑅+𝑃𝑃𝐶𝐶𝑝𝑝𝑝𝑝𝑝𝑝 𝐺𝐺𝑝𝑝𝑠𝑠 𝐹𝐹𝑝𝑝𝑝𝑝𝑅𝑅+𝑀𝑀𝐶𝐶𝑝𝑝ℎ𝑝𝑝𝑝𝑝𝐶𝐶 𝐺𝐺𝑝𝑝𝑠𝑠 𝐹𝐹𝑝𝑝𝑝𝑝𝑅𝑅 𝑠𝑠𝑟𝑟𝑝𝑝𝑚𝑚𝑅𝑅𝑝𝑝𝑅𝑅𝑇𝑇𝑝𝑝𝐶𝐶𝑝𝑝⁄𝐺𝐺𝑝𝑝𝑠𝑠 𝑆𝑆𝑝𝑝𝑟𝑟𝐶𝐶𝑝𝑝𝑚𝑚

All gas flows are based on anticipated process operation. In the scenario of raw gas combustion, no
enrichment gas will be present. Hourly emissions for NOx, CO, and VOC are calculated using the following
equation:

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 4-3
𝐻𝐻𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝐻𝐻 𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠 �𝑝𝑝𝑙𝑙ℎ𝑟𝑟�=𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟 �𝑝𝑝𝑙𝑙𝑀𝑀𝑀𝑀𝑀𝑀𝑝𝑝𝑝𝑝�× 𝐺𝐺𝑝𝑝𝑠𝑠 𝑠𝑠𝑝𝑝𝑝𝑝𝑅𝑅�𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�× 𝐻𝐻𝐻𝐻𝑉𝑉 �𝑀𝑀𝑝𝑝𝑝𝑝𝑠𝑠𝑠𝑠𝑠𝑠�𝐶𝐶𝑝𝑝𝑝𝑝𝐶𝐶𝐶𝐶𝑟𝑟𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟 𝑀𝑀𝑝𝑝𝑝𝑝𝑀𝑀𝑀𝑀𝑀𝑀𝑝𝑝𝑝𝑝

The NOx emission factor is per ‘TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor
Oxidizers’. CO and VOC emission factor are per AP-42 Chapter 13.5. PM and SO2 emission factor are per AP-
42 section 1.4.

Hourly emissions for PM and SO2 are calculated as follows:
𝐻𝐻𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝐻𝐻 𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠 �𝑝𝑝𝑙𝑙ℎ𝑟𝑟�=𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟 �𝑝𝑝𝑙𝑙𝑀𝑀𝑀𝑀𝑠𝑠𝑠𝑠𝑠𝑠�× 𝐺𝐺𝑝𝑝𝑠𝑠 𝑠𝑠𝑝𝑝𝑝𝑝𝑅𝑅�𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�𝐶𝐶𝑝𝑝𝑝𝑝𝐶𝐶𝐶𝐶𝑟𝑟𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝 𝑠𝑠𝑝𝑝𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟 𝑠𝑠𝑠𝑠𝑠𝑠𝑀𝑀𝑀𝑀𝑠𝑠𝑠𝑠𝑠𝑠

Annual PTE is calculated by multiplying hourly emissions of each scenario by the estimated hours of
operation for each scenario.
𝐴𝐴𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝐶𝐶𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠 (𝑝𝑝𝑝𝑝𝐻𝐻)=𝐻𝐻𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝐻𝐻 𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠 �𝑝𝑝𝑙𝑙ℎ𝑟𝑟� × 𝑆𝑆𝑝𝑝𝐶𝐶𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑔𝑔 𝐻𝐻𝑝𝑝𝑝𝑝𝑟𝑟𝑠𝑠�ℎ𝑟𝑟𝐻𝐻𝑟𝑟�× �1 𝑝𝑝𝑝𝑝𝑝𝑝2,000 𝑝𝑝𝑙𝑙�

4.2.3 GHG Emissions
4.2.3.1 Scenario 1a; Tail Gas Emitted
GHG pollutants expected to be emitted during operation scenario 1a include CO2 and CH4. Both pollutants
are present in the tail gas stream that is emitted without combustion. Hourly emissions from the pollutants
are obtained using the methodology detailed in Section 4.2.1. Calculations for GHG pollutants are based on
the calculated hourly emission rate and the global warming potential for each relevant pollutant. The global
warming potential is obtained from 40 CFR part 98, Subpart A, Table A-1.
CO2e Annual Emission (tpy)=�𝐶𝐶𝑆𝑆2 𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠 �𝑝𝑝𝑙𝑙ℎ𝑟𝑟�× 𝐺𝐺𝑀𝑀𝑃𝑃 𝐶𝐶𝑆𝑆2 �+�𝐶𝐶𝐻𝐻4 𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝𝑠𝑠 �𝑝𝑝𝑙𝑙ℎ𝑟𝑟�× 𝐺𝐺𝑀𝑀𝑃𝑃 𝐶𝐶𝐻𝐻4 �× 𝑆𝑆𝑝𝑝𝐶𝐶𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑔𝑔 𝐻𝐻𝑝𝑝𝑝𝑝𝑟𝑟𝑠𝑠�ℎ𝑟𝑟𝐻𝐻𝑟𝑟�× �1 𝑝𝑝𝑝𝑝𝑝𝑝2,000 𝑝𝑝𝑙𝑙�

N2O is not present in the unflared tail gas stream.
4.2.3.2 Scenarios 1b, 2a, 2b; Flaring
During operation scenarios that involve flaring, GHG emissions will include CO2, CH4, and N2O. The CO2 portion of the gas stream will be emitted without combustion, and the CH4 portion of the gas stream will
combust in the flare. Calculations for the GHG pollutants are based on the emission factor for each GHG
pollutant, relevant global warming potential, and total natural gas flow. Standard emission factors for CO2,
N2O, and CH4 are provided in 40 CFR Part 98, Subpart C, Table C-1 and Table C-2. The global warming
potential for each relevant pollutant is obtained from 40 CFR part 98, Subpart A, Table A-1. The total
natural gas flow is explained in Section 4.1.2.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 4-4
CO2e Annual Emissions (tpy)=�Emission Factor CO2 �lbMMscf�+Emission Factor CH4 �lbMMscf�× GWP CH4+Emission Factor N2O �lbMMscf�× GWP N2O� × �Total Natural Gas Flow �scfhr�/ �1 MMscf1,000,000 scf��× Operating Hours �hryr�× �1 ton2,000 lb�

4.2.4 HAP Emissions
During operation scenario 1a, HAP emissions will only include H2S within the tail gas stream which will be
emitted without flaring. During flaring operation scenarios (1b, 2a, 2b), H2S is converted to SO2, and
emission calculations are detailed in Section 4.1.1. Additionally, during flaring operation scenarios (1b, 2a,
2b), HAP emissions from natural gas combustion are calculated using the total natural gas flow and
emission factors per AP-42, Section 1.4, Table 1.4-3.
𝐻𝐻𝐴𝐴𝑃𝑃𝑠𝑠 (𝑝𝑝𝑝𝑝𝐻𝐻)=𝐸𝐸𝑚𝑚𝐶𝐶𝑠𝑠𝑠𝑠𝐶𝐶𝑝𝑝𝑝𝑝 𝐹𝐹𝑝𝑝𝑠𝑠𝑝𝑝𝑝𝑝𝑟𝑟 �𝑝𝑝𝑙𝑙𝑀𝑀𝑀𝑀𝑠𝑠𝑠𝑠𝑠𝑠� × �𝑇𝑇𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝑁𝑁𝑝𝑝𝑝𝑝𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝 𝐺𝐺𝑝𝑝𝑠𝑠 𝐹𝐹𝑝𝑝𝑝𝑝𝑅𝑅�𝑠𝑠𝑠𝑠𝑠𝑠ℎ𝑟𝑟�/ �1 𝑀𝑀𝑀𝑀𝑠𝑠𝑠𝑠𝑠𝑠1,000,000 𝑠𝑠𝑠𝑠𝑠𝑠��× 𝑆𝑆𝑝𝑝𝐶𝐶𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑔𝑔 𝐻𝐻𝑝𝑝𝑝𝑝𝑟𝑟𝑠𝑠�ℎ𝑟𝑟𝐻𝐻𝑟𝑟�× �1 𝑝𝑝𝑝𝑝𝑝𝑝2,000 𝑝𝑝𝑙𝑙�

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 5-1
5. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS
In the State of Utah, under R307-401-5(2)(d), Notice of Intent, every facility, operation, or process that
proposes any activity that would emit an air contaminant into the air must consider best available control
technology (BACT) for a proposed new source or modification.4 The BACT analysis below addresses all units
installed, or otherwise addressed in this NOI air permit application.
5.1 Tail Gas H2S Emissions
5.1.1 Step 1 - Identify All Control Technologies
The available control technologies for treating H2S have been identified through a review of available
literature and databases. GreenGas evaluated the following:
► California Air Resources Board (CARB) Database;
► RACT/BACT/LAER Control (RBLC) Database Search with the “Process Type Code” of 50.002 for Natural
Gas/Gasoline Processing Plants. (Search conducted on August 5, 2024);
► Technical Support Document for Dairy Manure Anaerobic Digester Systems with Digester Gas Fueled
Engine Generators, Published by the Washington Department of Ecology;
► Review of Biogas Cleaning, Published by Meat & Livestock Australia Limited;
► Dairy Environmental Systems Program, Cornell University;
► Available online permits; and
► Information from similar facilities.

GreenGas considered the following sulfur treatment methods for implementation at the Hyrum site:
► Caustic Scrubber;
► Dry Techniques;
► Iron Removal Methods;
► Biological Methods; and
► Flare/Thermal Oxidation.
5.1.2 Step 2 – Eliminate Technically Infeasible Control Options
Caustic Scrubber
A caustic scrubber is a device in which tail gas flows countercurrent to a solution of sodium hydroxide
(caustic) and water. H2S is highly soluble in water and when dissolved results in an acidic solution. The
dissolved H2S readily reacts with the caustic solution to form sodium sulfite and sodium hydrosulfite which
precipitate out of the solution. Due to the insoluble nature of these precipitates, the caustic solution is not
regenerative and often requires offsite disposal or sale.5 Since this process uses a solvent which cannot be
easily regenerated, caustic scrubbers are most often applied in situations where small volumes of H2S need
to be removed, typically referred to as scavenging when combined with other control technologies.6 This
system is generally used for systems with a sulfur production capacity between 0.1 and 10 tons per day.

4 UAC R307-401-4
5 Meat & Livestock Australia Limited Review of Biogas Cleaning, published in June of 2012
6 American Fuel and Petrochemical Manufacturers Paper AM-14-48

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 5-2
The maximum untreated emission rate of H2S is anticipated to be less than 0.1 tons per day; therefore, this
technology is infeasible.
Dry Techniques
The most common dry technique is to install a packed bed scrubber containing activated carbon. This
control method has been used to effectively treat H2S at landfills and wastewater treatment plants.
Activated carbon is a form of carbon that has been processed to make it extremely porous to increase the
surface area available for adsorption or other chemical reactions. Activated carbon can be impregnated with
alkaline or oxide solids to improve adsorption of H2S. Common applications include sodium hydroxide,
sodium carbonate, potassium hydroxide, potassium iodide, and metal oxides.7 Typically, 20 – 25% loading
by weight of H₂S can be achieved.8
Upon saturation of the activated carbon, the spent media must be replaced with fresh material. While spent
activated carbon can be thermally regenerated using the same process in which it was made, it is typically
more economically favorable to simply purchase new activated carbon from a supplier. The continual
replacement of spent media results in a significant solid waste stream which lacks an environmentally
friendly disposal method. Additionally, this replacement results in relatively high labor costs due to materials
handling/disposal.9 Due to the large amounts of waste anticipated and low control efficiency, activated
carbon scrubbing is considered technically impracticable and not further considered as BACT.
Iron Removal Methods
Iron can be added in a variety of methods to reduce H2S in a fuel or tail gas stream. Iron has the ability to
readily donate electrons to a reaction, making it an excellent reducing agent or catalyst for other sulfur
reactions. Upon a review of available iron removal methods, GreenGas determined that Vacuum Adsorption
Vessel (VAV) technology was most compatible with the process. This technology involves both an iron media
that extracts the H2S and a vessel specially crafted to house the media. The vessel is specifically designed
for digestors and similar processes to facilitate even gas flow through the media bed with low pressure
restriction.10

The media used is an iron-oxide-hydroxide (FeO(OH)), which undergoes two distinct reactions when it
encounters hydrogen sulfide. First is the initial absorption reaction:
𝐴𝐴𝑙𝑙𝑠𝑠𝑝𝑝𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑝𝑝: 2𝐹𝐹𝐶𝐶(𝑆𝑆𝐻𝐻)3 + 2𝐻𝐻2𝑆𝑆 → 𝐹𝐹𝐶𝐶2𝑆𝑆3 + 6𝐻𝐻2𝑆𝑆

A secondary reaction then occurs, under proper moisture and oxygen conditions, which naturally
regenerates the catalyst.11
𝑅𝑅𝐶𝐶𝑔𝑔𝐶𝐶𝑝𝑝𝐶𝐶𝑟𝑟𝑝𝑝𝑝𝑝𝐶𝐶𝑝𝑝𝑝𝑝: 𝐹𝐹𝐶𝐶2𝑆𝑆3 + 1
12 𝑆𝑆2 + 3𝐻𝐻2𝑆𝑆→2𝐹𝐹𝐶𝐶(𝑆𝑆𝐻𝐻)3 + 3𝑆𝑆

7 Technical Support Document for Dairy Manure Anaerobic Digester Systems with Digester Gas Fueled Engine Generators,
Published by the Washington Department of Ecology
8 California Biomass Collaborative, under the direction of the California Energy Commission, Comparative Assessment of
Technology Options for Biogas Clean‐up, October 2014
9 Solid Waste Association of North America, Hydrogen Sulfide Mitigation Strategy for a Class I Landfill, July 2015
10 Potential vendor website: How Do You Remove H2S From Biogas? - Interra Global
11 Potential vendor website: How Do You Remove H2S From Biogas? - Interra Global

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 5-3

The sulfur precipitates out as a powdery coating and can be easily disposed of.12 This regeneration reaction
does not occur indefinitely but does prolong the media life significantly. In conversations with the vendor, it
is anticipated that the sulfur content can be lowered to 50 ppmv, which represents a 96-99% control
efficiency. Use of a VAV containing iron-oxide-hydroxide is considered technically feasible
Biological Methods
There are a variety of biological agents that process H2S and reduce the potential for air emissions. These
methods have been implemented as a method for reducing the sulfur content of the raw biogas prior to
further treatment. Sulfur-oxidizing bacteria and a small amount of oxygen are commonly inserted into a
digester to breakdown the H2S produced through fermentation. 13 In this process, bacteria that convert H2S
to elemental sulfur grow on digester walls and surfaces above the liquid surface, on the liquid surface, or on
a biological filter medium. Research and experience indicate that the start-up period for a biological
treatment system can be anywhere from a few days to a month.14,15 This slow start-up time is a result of
the culture needing time to develop and for the microorganisms to multiply to a level sufficient for the
treatment of the desired pollutant. As a result, this technology is considered technically impracticable and is
not further considered.
Flare/Thermal Oxidation
Properly designed flares/thermal oxidization systems can be expected to achieve 98% control of H2S
emissions. The thermal oxidizer or flare would require a natural gas burner which produces secondary
criteria pollutants and produces high SO2 emissions from the conversion of H2S. Furthermore, the tail gas
stream contains very little methane which results in a very low BTU value. To ensure proper combustion,
enrichment gas would be required. This technology is considered technically feasible.
5.1.3 Steps 3- Rank Remaining Technologies by Control Effectiveness
VAV absorption and Flare/Thermal Oxidation technologies are considered technically feasible and are ranked
as follows:

Technology Ranking Control
Efficiency
VAV Absorption 1 96-99%
Flare/Thermal Oxidation 2 98%

While both technologies have similar removal efficiencies, VAV absorption produces no secondary onsite air
emissions and thus is ranked higher than a flare.

12 Potential vendor website: How Do You Remove H2S From Biogas? - Interra Global
13 Technical Support Document for Dairy Manure Anaerobic Digester Systems with Digester Gas Fueled Engine Generators,
General Order of Approval No. 12AQ-GO-01, March 2102.
14 Bioreactors for treatment of VOC and Odors – A review, published by the Journal of Environmental Management, available
online February 2010
15 Development And Application Of Biological H2S Scrubbers For Treatment Of Digester Gas, published in conjunction with the California Energy Group

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 5-4
5.1.4 Step 5 – Select BACT
GreenGas proposes to utilize VAV technology during all normal operations. Should H2S emissions or other
odor causing compounds be detected in the surrounding community, GreenGas would like to permit the use
of a flare as an optional secondary control to be used in series with the VAV.

Under emergency and maintenance conditions, such as over production of the digestor or breakdown of the
VAV, GreenGas proposes to operate the flare as a backup primary control device.
5.2 Flaring Emissions
GreenGas proposes to operate a flare as a secondary control technology during normal operating scenario,
and as a backup primary control device under emergency/maintenance scenarios.

EPA’s RBLC was queried on August 5, 2024 to identify waste gas controls for similar landfill gas/biogas processing facilities. Additionally, the UDAQ recently developed an Oil and Gas General Permitting Program
for similar fossil natural gas processing sources codified in the R307-500 series of rules.16 All sources
reviewed indicated that the design of the flare was the only available control option.
The proposed flare has an H2S destruction efficiency of 98% and will be operated in accordance with
manufacturer recommendations and general good combustion practices. GreenGas proposes that the
installation of a well-designed flare which is properly operated and maintained meets BACT.
5.3 Equipment Leaks
During the processing of renewable natural gas, minimal emissions from component leaks are anticipated.
H2S emissions associated with equipment leaks are estimated at 0.04 tpy. As such, no further BACT analysis
has been completed, as emissions are minimal and additional controls would not be economically feasible.

16 As seen in section 8 these regulations are not applicable as GreenGas is a renewable natural gas plant.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 6-1
6. EMISSION IMPACT ANALYSIS
Appendix Table B-1 compares criteria pollutant maximum proposed emissions to applicable modeling
thresholds contained in R307-410-4.

Although modeling threshold have not been surpassed, an air dispersion modeling analysis that
demonstrates the impacts of the site-wide H2S emissions from the proposed process has been prepared and
will be presented to UDAQ with this submittal in a separate document.

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7. NONATTAINMENT/MAINTENANCE AREAS - OFFSETTING
Offset Applicability
PM2.5 Offsets
PM2.5 offsets are required for sources located in serious nonattainment areas that are a major source of
PM2.5 (i.e., 70 tpy of direct PM2.5 or individual PM2.5 precursors) or have a major modification of an existing
source with an emissions increase greater than 10 tpy of direct PM2.5, 40 tpy of SO2, 40 tpy NOX, or 40 tpy
of VOCs. 17 The proposed RNG Facility is not in a serious nonattainment area of PM2.5; therefore, PM2.5
offsets are not required for the RNG Facility.
7.1.1 PM10 Offsets
PM10 offsets requirements are described in UAC R307-421-2. They apply to new or modified sources that are
located in, or impact, Salt Lake County or Utah County and increase SO2 or NOX by 25 tpy or more. 18 The
proposed RNG Facility is located in Cache County and is proposing emissions of SO2 and NOX below the 25
tpy limit. The RNG Facility is therefore not subject to the PM10 offset requirements of R307-421.
7.1.2 Ozone Offsets
Ozone offsets requirements recorded in UAC R307-420-3(2) and VOC offsets are applicable to significant
sources located within or impacting an ozone nonattainment area of the NAAQS. In summary, significant
sources located in Davis County or Salt Lake County shall offset the proposed increase in VOC emissions.
The proposed RNG Facility is located in Cache County and is therefore not subject to the Ozone offsets of
R307-420-3.

17 UAC R307-403-5(20(c). Offset Requirements.
18 UAC R307-421-3. Offset Requirements.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-1
8. APPLICABLE REGULATIONS
This section of the application summarizes the air permitting requirements and key air quality regulations
that will apply to the proposed equipment under both federal and state permitting programs. Applicability to
Utah Administrative Code (UAC) Title R307, NSR, Title V, New Source Performance Standards (NSPS), and
National Emission Standards for Hazardous Air Pollutants (NESHAP) is evaluated in this section.

After evaluating all local and federal regulations, it has been determined that GreenGas is not regulated as a
typical oil and gas industry because it produces renewable natural gas. Both UDAQ air quality rules such as
UAC R307 Series 500, and Federal rules such as 40 CFR 60 Subparts OOOOa and OOOOb, focus on non-
renewable gas operations. This distinction exempts GreenGas from these rules, as detailed below.
UDAQ Air Quality Rules
GreenGas has evaluated the applicability of each rule under the Utah Administrative Code (UAC) Title R307.
Rules generally applicable to GreenGas but not affected by this project have not been addressed.
Table 8-1. Evaluation of UDAQ Air Quality Rules
Reference Regulation Name Applicability
Yes No
R307-101 General Requirements X
R307-102

General Requirements: Broadly Applicable
Requirements X
R307-103

Administrative Procedures X
R307-104 1 Conflict of Interest X
R307-105

General Requirements: Emergency controls X
R307-107

General Requirements: Breakdowns X
R307-110

General Requirements: State Implementation
Plan X
R307-115

General Conformity X
R307-120 General Requirements: Tax Exemption for Air
Pollution Control Equipment X
R307-121 General Requirements: Clean Air and Efficient
Vehicle Tax Credit X
R307-122 General Requirements: Heavy Duty Vehicle Tax
Credit X
R307-123 General Requirements: Clean Fuels and Vehicle Technology Grant and Loan Program X
R307-124 General Requirements: Conversion to Alternative
Fuel Grant Program X
R307-125 Clean Air Retrofit, Replacement, and Off-Road
Technology Program X

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-2
Reference Regulation Name Applicability
Yes No
R307-130

General Penalty Policy X
R307-135 Enforcement Policy for Asbestos Hazard
Emergency Response Act X
R307-150 Emission Inventories X
R307-165 Emission Testing X
R307-170 Continuous Emission Monitoring Program X
R307-201 Emission Standards: General Emission Standards X
R307-202 Emission Standards: General Burning X
R307-203

Emission Standards: Sulfur Content of Fuels x
R307-204 Emission Standards: Smoke Management X
R307-205 Emission Standards: Fugitive Emissions and
Fugitive Dust X
R307-206 Emission Standards: Abrasive Blasting X
R307-207 Residential Fireplaces and Solid Fuel Burning
Devices X
R307-208 Outdoor Wood Boilers X
R307-210 2 Standards of Performance for New Stationary
Sources X
R307-214 2 National Emission Standards for Hazardous Air
Pollutants X
R307-220 Emission Standards: Plan for Designated Facilities X
R307-221 Emission Standards: Emission Controls for Existing Municipal Solid Waste Landfills X
R307-222 Emission Standards: Existing incinerator for
Hospital, Medical, Infectious Waste X
R307-223 Emission Standards: Existing Small Municipal
Waste Combustion Units X
R307-224 Mercury Emission Standards: Coal Fired Electric
Generating Units X
R307-230
NOX Emission Limits for Natural Gas-Fired Water
Heaters X
R307-250 Western Backstop Sulfur Dioxide Trading Program X
R307-301 Utah and Weber Counties: Oxygenated Gasoline Program as a Contingency Measure X
R307-302 Solid Fuel Burning Devices X
R307-303 Commercial Cooking X

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-3
Reference Regulation Name Applicability
Yes No
R307-304

Solvent Cleaning X
R307-305

Nonattainment and Maintenance Areas for PM10: Emission Standards X
R307-306 PM10 Nonattainment and Maintenance Areas:
Abrasive Blasting X
R307-307 Road Salting and Sanding X
R307-309
Nonattainment and Maintenance Areas for PM10
and PM2.5: Fugitive Emissions and Fugitive Dust X
R307-310 Salt Lake County: Trading of Emission Budgets for Transportation Conformity X
R307-311 Utah County: Trading of Emission Budgets for
Transportation Conformity X
R307-312 Aggregate Processing Operations for PM2.5
Nonattainment Areas X
R307-320
Ozone Maintenance Areas and Ogden City:
Employer Based Trip Reduction X
R307-325
Ozone Nonattainment and Maintenance Areas:
General Requirements X
R307-326
Ozone Nonattainment and Maintenance Areas:
Control of Hydrocarbon Emissions in Petroleum
Refineries
X
R307-327 Ozone Nonattainment and Maintenance Areas:
Petroleum Liquid Storage X
R307-328

Gasoline Transfer and Storage X
R307-335 Degreasing X
R307-341
Ozone Nonattainment and Maintenance Areas:
Cutback Asphalt X
R307-342 Adhesives and Sealants X
R307-343 Wood Furniture Manufacturing Operations X
R307-344 Paper, Film, and Foil Coatings X
R307-345 Fabric and Vinyl Coatings X
R307-346 Metal Furniture Surface Coatings X
R307-347 Large Applicable Surface Coatings X
R307-348 Magnet Wire Coatings X
R307-349 Flat Wood Panel Coating X
R307-350 Appliance Pilot Light X
R307-351

Graphic Arts X

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-4
Reference Regulation Name Applicability
Yes No
R307-352 Metal Container, Closure, and Coil Coatings X
R307-353 Plastic Parts Coatings X
R307-354 Automotive Refinishing Coatings X
R307-355 Aerospace Manufacture and Rework Facilities X
R307-356 Appliance Pilot Light X
R307-357 Consumer Products X
R307-361

Architectural Coatings X
R307-401 Permit: New and Modified Sources X
R307-403 Permits: New and Modified Sources in
Nonattainment and Maintenance Areas X
R307-405 Permits: Major Sources in Attainment or
Unclassified Areas (PSD) X
R307-406 1 Visibility X
R307-410

Permits: Emission Impact Analysis X
R307-414

Permits: Fees for Approval Orders X
R307-415

Permits: Operating Permit Requirements X
R307-417 Permits: Acid Rain Sources X
R307-420
Permits: Ozone Offset Requirements in Salt Lake
County and Utah County X
R307-421

Permits: PM10 Offset Requirements in Salt Lake County and Utah County X
R307-424 Permits: Mercury Requirements for Electric
Generating Units X
R307-501 to
511
Oil and Gas Industry X
R307-801 Utah Asbestos Rule X
R307-840
Lead-Based Paint Program Purpose, Applicability,
and Definitions X
R307-841 Residential Property and Child-Occupied Facility
Renovation X
R307-842 Lead-Based Paint Activities X
1. At the time of submission of this NOI air permit application, this rule does not apply.
2. Applicable NSPS and NESHAP regulations are detailed under appropriate project headings.
8.1.1 UAC R307-101 General Requirements
Chapter 19-2 and the rules adopted by the Air Quality Board constitute the basis for control of air pollution
sources in the state. These rules apply and will be enforced throughout the state and are recommended for

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-5
adoption in local jurisdictions where environmental specialists are available to cooperate in implementing rule
requirements.
NAAQS, NSPS, National Prevention of Significant Deterioration of Air Quality (PSD) standards, and the NESHAP
apply throughout the nation and are legally enforceable in Utah.

GreenGas will comply and conform to the definitions, terms, abbreviations, and references used in the
R307-101 and 40 CFR.
8.1.2 UAC R307-107 General Requirements: Breakdowns
GreenGas will report breakdowns at the RNG Facility within 24 hours via telephone, electronic mail, fax, or
other similar method and provide detailed written description within 14 days of the onset of the incident to
UDAQ. Breakdown reports will include all reporting details outlined in R307-107-2, including, but not limited
to, the cause and nature of the event, estimated quantity of emissions, and time of emissions.
8.1.3 UAC R307-201 Emission Standards: General Emission Standards
All rules applicable to GreenGas are incorporated by reference from 40 CFR Part 60. Applicability and
requirements for these rules are outlined in Section 8.2 of this submittal.
8.1.4 UAC R307-410-8 Permits: Permit New and Modified Sources – Approval
Order
(1) The director will issue an AO if all conditions and regulations have been met.
(a) The degree of pollution control for emissions, to include fugitive emissions and fugitive dust, is at
least best available control technology. When determining best available control technology for a
new or modified source in an ozone nonattainment or maintenance area that will emit VOCs or NOX,
best available control technology shall be at least as stringent as any Control Technique Guidance
document that has been published by EPA that is applicable to the source.
(b) The proposed installation will meet the applicable requirements of:
(i) R307-403, Permits: New and Modified Sources in Nonattainment Areas and Maintenance
Areas;
(ii) R307-405, Permits: Major Sources in Attainment or Unclassified Areas (PSD);
(iii) R307-406, Visibility;
(iv) R307-410, Emissions Impact Analysis;
(v) R307-420, Permits: Ozone Offset Requirements in Davis and Salt Lake Counties;
(vi) R307-210, National Standards of Performance for New Stationary Sources;
(vii) National Primary and Secondary Ambient Air Quality Standards;
(viii) R307-214, National Emission Standards for Hazardous Air Pollutants;
(ix) R307-110, General Requirements. Utah State Implementation Plan; and
(x) All other provisions of R307.
(2) GreenGas’s AO will require that all pollution control equipment be adequately and properly maintained.
(3) Receipt of an AO does not relieve any owner or operator of the responsibility to comply with the
provisions of R307 or the State Implementation Plan.

BACT provisions specified in UAC R307-401 have been applied through control equipment installed and
monitoring conditions.

The Facility will comply with all applicable requirements detailed above.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-6
8.1.5 UAC R307-414 Permits: Fees for Approval Orders
Fees associated with the submission of this NOI air permit application are addressed in Section 2 of this
submittal.
8.2 New Source Performance Standards
NSPS apply to certain types of equipment that are newly constructed, modified, or reconstructed after a
given applicability date. Only the NSPS subparts that may be potentially applicable to the RNG Facility are
addressed in this section.
8.2.1 40 CFR 60 Subpart A – General Provisions
All affected sources subject to source-specific NSPS are subject to the general provisions of NSPS Subpart A
unless specifically excluded by the source-specific NSPS. Subpart A requires initial notification, performance
testing, recordkeeping and monitoring, provides reference methods, and mandates general control device
requirements for all other subparts as applicable.
8.2.2 40 CFR 60 OOOOa – Crude Oil and Natural Gas Facilities
NSPS Subpart OOOOa applies to onshore affected facilities located within the Crude Oil and Natural Gas
Production source category, as defined in §60.5430a, for which you commence construction, modification,
or reconstruction after September 18, 2015. The RNG Facility does not meet criteria for any of the affected
facilities under the rule. Therefore, the rule does not apply.
8.2.3 40 CFR 60 OOOOb – Standards of Performance for Crude Oil and Natural Gas
NSPS Subpart OOOOb sets emissions standards for GHGs and VOCs for facilities involved in crude oil and
natural gas production. This subpart applies to facilities that commenced construction, modification, or
reconstruction after December 6, 2022. The RNG Facility does not meet criteria for any of the affected
facilities under the rule. Therefore, the rule does not apply.

There are no other NSPS potentially applicable to the RNG Facility.
8.3 National Emissions Standards for Hazardous Air Pollutants
8.3.1 40 CFR 61 – National Emission Standards for Hazardous Air Pollutants
NESHAP, located in 40 CFR 61 and 63, have been promulgated for source categories that emit HAP to the
atmosphere. A facility that is a major source of HAP is defined as having potential emissions greater than 25
tpy of total HAP and/or 10 tpy of an individual HAP. Facilities with a potential to emit HAP at an amount less
than that which is defined as a major source are otherwise considered an area source. The RNG Facility has
potential HAP emissions below the major source thresholds and is, therefore, an area source of HAP.

The NESHAP allowable emissions limits are most often established on the basis of a maximum achievable
control technology (MACT) determination for the particular source. The NESHAP apply to sources in
specifically regulated industrial source categories (Clean Air Act Section 112(d)) or on a case-by-case basis
(Section 112(g)) for facilities not regulated as specific industrial source types. The determination of
applicability to NESHAP requirements are detailed in the following sections.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants 8-7

The National Emission Standards for Hazardous Air Pollutants (NESHAP) under 40 CFR Part 61 are pollutant-
specific regulations that limit emissions of HAP. GreenGas does not operate any emission units subject to
these requirements. Therefore, no Part 61 NESHAP regulations apply.
8.3.2 40 CFR 63 Subpart A – General Provisions
NESHAP Subpart A, General Provisions, contains national emission standards for HAP defined in Section
112(b) of the Clean Air Act. All affected sources, which are subject to another NESHAP, are subject to the
general provisions of NESHAP Subpart A, unless specifically excluded by the source-specific NESHAP.
8.3.3 40 CFR 63 Subpart HHH – Natural Gas Transmission and Storage Facilities
40 CFR 63 Subpart HHH regulates HAP emissions from natural gas transmission and storage facilities that
transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end
user (if there is no local distribution company), and that are major sources of HAP. The RNG Facility will not
meet the definition of a natural gas transmission facility and will not be a major source. Therefore, the rule
does not apply to the RNG Facility.

There are no other NESHAPs potentially applicable to the RNG Facility.
8.4 40 CFR Part 98 Greenhouse Gas Emissions
The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this
part apply to the owners and operators of any facility that is located in the U.S. or under or attached to the
Outer Continental Shelf (as defined in 43 U.S.C. 1331) and that meets the requirements of either paragraph
(a)(1), (a)(2), or (a)(3) of 40 CFR 98.2; and any supplier that meets the requirements of paragraph (a)(4)
of 40 CFR 98.2. The RNG Facility will operate a flare that is a source listed in Subpart C of 40 CFR Part 98 –
General Stationary Fuel Combustion Sources. GreenGas will comply with reporting requirements of Part 98,
as applicable to the flare.

GreenGasUSA / RNG Facility Permit Application Trinity Consultants A
APPENDIX A. FORMS

Form 1 Date __________________
Notice of Intent (NOI) Application Checklist
Company __________________
Utah Division of Air Quality
New Source Review Section
Source Identification Information [R307-401-5]
1. Company name, mailing address, physical address and telephone number 
2. Company contact (Name, mailing address, and telephone number)
3.Name and contact of person submitting NOI application (if different than 2) 4.Source Universal Transverse Mercator (UTM) coordinates 
5. Source Standard Industrial Classification (SIC) code 
6.Area designation (attainment, maintenance, or nonattainment)
7.Federal/State requirement applicability (NAAQS, NSPS, MACT, SIP, etc.)
8.Source size determination (Major, Minor, PSD) 9. Current Approval Order(s) and/or Title V Permit numbers 
NOI Application Information: [R307-401]










N/A 
N/A 
A.Air quality analysis (air model, met data, background data, source impact analysis) N/A 
1.Detailed description of the project and source process
2.Discussion of fuels, raw materials, and products consumed/produced3.Description of equipment used in the process and operating schedule
4.Description of changes to the process, production rates, etc.
5.Site plan of source with building dimensions, stack parameters, etc.
6.Best Available Control Technology (BACT) Analysis [R307-401-8]A.BACT analysis for all new and modified equipment
7.Emissions Related Information: [R307-401-2(b)]
A.Emission calculations for each new/modified unit and site-wide
(Include PM10, PM2.5, NOx, SO2, CO, VOCs, HAPs, and GHGs)B.References/assumptions, SDS, for each calculation and pollutant
C.All speciated HAP emissions (list in lbs/hr)
8.Emissions Impact Analysis – Approved Modeling Protocol [R307-410]
A.Composition and physical characteristics of effluent(emission rates, temperature, volume, pollutant types and concentrations)
9.Nonattainment/Maintenance Areas – Major NSR/Minor (offsetting only) [R307-403]
A.NAAQS demonstration, Lowest Achievable Emission Rate, Offset requirements
B.Alternative site analysis, Major source ownership compliance certification
10.Major Sources in Attainment or Unclassified Areas (PSD) [R307-405, R307-406]
B.Visibility impact analysis, Class I area impact
11.Signature on Application
N/A 
Note: The Division of Air Quality will not accept documents containing confidential information or data.
Documents containing confidential information will be returned to the Source submitting the application.
CNVIROF
ONME
A
AIR QUALITY
Form 2
Company Information/Notice of Intent (NOI)
Utah Division of Air Quality
New Source Review Section
Application for:VInitial ApprovalOrder
Date August 2024
Approval OrderModification
General Owner and Source lnformation
1.Company name and mailing address:
GreenGasUSA
4900 O'Hear Ave,Suite 10C
North Charleston,SC 29405
PhoneNo.:[phone]
Fax No.:
3.Source name and physical address (if different from
above):
410 North 200 West
Hyrum,Utah
Phone no.:
Fax no.:
5.The Source is located in:Cache
2.Company**contact for environmental matters:
Casey Murakami
Phoneno.:([phone]
Email:[e-mail]
**Company contact only;consutant or independent contractor contact
information can be provided ina coverletter
4.Source Property Universal Transverse Mercator
coordinates (UTM),including System and Datum:
UTM:12
X:
Y:
428,370 m
4,610,901 m
6.Standard Industrial Classification Code (SIC)1311
DATED:
County
7.If request for modification,AO#to be modified:DAQE #
8.Brief (50 words or less)description of process.
GreenGasUSA is proposing to construct a renewable natural gas (RNG)facility to be co-located at the
existing Swift Beef Plant.The proposed RNG Facility will treat the biogas (raw gas)from the
anaerobic digestors anddeliver the treated gas toa natural gas pipeline distribution system.
Electronic NOI
9.A complete and accurate electronic NOl submitted to DAQ Permitting Mangers Jon Black ([e-mail])or Alan
Humpherys ([e-mail])can expedite review process.Please mark application type.
Hard Copy Submittal ElectronicCopy Submittal
Authorization/Signature
I hereby certify that the information and data submitted in and with this application is completely true,accurate and
complete,based oneatgagbte Inq uiry made by me and to the best of my knowledge and belief.
Signature:
SeoT
Name (Type or print)
Title:COO
Telephone Number:
()854 200 2oyy
Email:
1 of 1
WiLsON
Date:8/4/24
Both
Page 1 of 1
Form 3 Company____________________
Process Information Site________________________
Utah Division of Air Quality
New Source Review Section
Process Information - For New Permit ONLY
1.Name of process:2.End product of this process:
3.Process Description*:
Operating Data
4.Maximum operating schedule:
__________ hrs/day
__________days/week
__________weeks/year
5.Percent annual production by quarter:
Winter ________ Spring _______
Summer ________ Fall _______
6.Maximum Hourly production (indicate units.):
_____________
7.Maximum annual production (indicate units):
________________
8.Type of operation:
Continuous Batch Intermittent
9.If batch, indicate minutes per cycle ________
Minutes between cycles ________
10. Materials and quantities used in process.*
Material Maximum Annual Quantity (indicate units)
11.Process-Emitting Units with pollution control equipment*
Emitting Unit(s) Capacity(s) Manufacture Date(s)
*If additional space is required, please create a spreadsheet or Word processing document and attach to form.
See Attached NOI.
Utah Division of Air Quality
New Source Review Section Company___________________________
Site/Source__________________________
Form 4 Date_______________________________
Flare Systems
Equipment Information
1. Manufacturer:
_________________________
Model no.:
_________________________
(if available)
2. Design and operation shall be in accordance with 40CFR63.11. In addition
to the information listed in this form, provide the following: an assembly
drawing with dimensions, interior dimensions and features, flare’s
maximum capacity in BTU/hr.
3.Characteristics of Waste Gas Stream Input
Components Min. Value Expected
(scfm @ 68 oF, 14.7 psia)
Ave. Value Expected
(scfm @ 68oF, 14.7 psia)
Design Max.
(scfm @ 68oF, 14.7 psia)
a.
b.
c.
d.
e.
f.
g.
h.
4. Percent of time this
condition occurs
5.Flow rate: Minimum Expected Design Maximum Temp oF Pressure (psig)
Waste Gas Stream _______________ _______________ _______ ____________
Fuel Added to Gas Stream _______________ _______________ _______ ____________
Heat content of the gas to be flared ______________ BTU/ft3
6. Number of pilots 7. Type of fuel 8.Fuel Flow Rate (scfm @ 68oF & 14.7 psia) per pilot
Page 1 of 3
GreenGasUSA
Hyrum RNG Facility
August 2024
See NOI
144 scf/min
60 scf/min
775 scf/min
112 scf/min
80-90 1-4
700
1 Natural Gas 1.67
Page 2 of 3
Flare Systems
Form 4
(Continued)
Steam Injection
9. Steam pressure (psig)
Minimum Expected __________________
Design Maximum __________________
10. Total steam flow Rate (lb/hr)
11. Temperature (oF)12. Velocity (ft/sec)
13. Number of jet streams 14. Diameter of steam jets (inches)
15. Design basis for steam injected (lb steam/lb hydrocarbon)
Water Injection
16. Water pressure (psig)
Minimum Expected __________________
Design Maximum __________________
17. Total Water Flow Rate (gpm)
Minimum Expected __________________
Design Maximum __________________
18. Number of water jets 19. Diameter of Water jets (inches)
20. Flare height (ft)21. Flare tip inside diameter (ft)
Emissions Calculations (PTE)
22. Calculated emissions for this device
PM10 _________Lbs/hr_________ Tons/yr PM2.5 __________Lbs/hr________ Tons/yr
NOx __________Lbs/hr_________ Tons/yr SOx ___________Lbs/hr________ Tons/yr
CO __________Lbs/hr_________ Tons/yr VOC ___________Lbs/hr________Tons/yr
CO2 _________Tons/yr CH4 ___________Tons/yr
N2O _________Tons/yr
HAPs_________Lbs/hr (speciate)__________Tons/yr (speciate)
Submit calculations as an appendix. If other pollutants are emitted, include the emissions in the appendix.
See Appendix B
Page 3 of 3
Instructions - Form 4 Flare Systems
NOTE: 1. Submit this form in conjunction with Form 1 and Form 2.
2.Call the Division of Air Quality (DAQ) at [phone] if you have problems or questions in filling out
this form. Ask to speak with a New Source Review engineer. We will be glad to help!
1. Specify the manufacturer and model number.
2.Supply an assembly drawing, dimensioned and to scale of the interior dimensions and features of the
equipment.
3.Supply the specifications of the fuel components in the waste gas stream.
4.Indicate what percent of the time the waste gas stream is at minimum, average, and maximum value.
5.Supply the specifications of the total waste gas stream and the fuel added to the gas stream.
6. Indicate the number of pilots in the flare.
7. Specify the type of fuel to be used.
8. Specify the fuel flow rate.
9. Indicate the minimum and design maximum steam pressure for steam injection.
10. Supply the steam flow rate.
11. Supply the temperature of the steam.
12. Specify the velocity of the steam.
13. Indicate the number of jet streams.
14. Give the diameter of the steam jets.
15. Give the design basis for the steam injection.
16.Specify the water pressure at minimum and design maximum using water injection.
17. Give the total water flow rate at minimum and design maximum.
18. Supply the number of water jets.
19. Give the diameter of the water jets.
20. Supply the flare height.
21. Supply the flare tip inside diameter.
22. Supply calculations for all criteria pollutants and HAPs. Use AP-42 or Manufacturers’ data to complete your
calculations.
U:aq\ENGINEER\GENERIC\Forms 2010\ Form04 Flare Systems.doc
Revised 12/20/10
Page 1 of 1
Company___________________________
Site _____________________________
Form 5
Emissions Information
Criteria/GHGs/ HAP’s
Utah Division of Air Quality
New Source Review Section
Potential to Emit* Criteria Pollutants & GHGs
Criteria Pollutants Permitted Emissions
(tons/yr)
Emissions Increases
(tons/yr)
Proposed Emissions
(tons/yr)
PM10 Total
PM10 Fugitive
PM2.5
NOx
SO2
CO
VOC
VOC Fugitive
NH3
Greenhouse Gases CO2e CO2e CO2e
CO2
CH4
N2O
HFCs
PFCs
SF6
Total CO2e
*Potential to emit to include pollution control equipment as defined by R307-401-2.
Hazardous Air Pollutants** (**Defined in Section 112(b) of the Clean Air Act )
Hazardous Air
Pollutant***
Permitted Emissions
(tons/yr)
Emission Increase
(tons/yr)
Proposed
Emission (tons/yr)
Emission Increase
(lbs/hr)
Total HAP
*** Use additional sheets for pollutants if needed
Attached in Appendix B
Attached in Appendix B

GreenGasUSA / RNG Facility Permit Application Trinity Consultants B
APPENDIX B. EMISSION CALCULATION

GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-1. GreenGasUSA Average Annual Emissions Summary
NOX NO2 CO PM10 PM2.5 SO2 VOC CO2e Total HAPs
1a Treated Tail Gas Emitted -------6890.78 0.421bTreated Tail Gas Combusted 2.63 2.63 5.90 0.14 0.14 0.78 12.57 5658.60 0.042aUntreated Tail Gas Combusted 0.24 0.24 0.53 0.01 0.01 2.08 1.13 506.74 0.03
2b Raw Gas Combusted 0.91 0.91 2.05 0.05 0.05 1.98 4.36 1050.00 0.03-------442.57 0.04
3.54 3.54 7.95 0.19 0.19 2.86 16.93 8383.35 0.49
100 100 250 250 100 100 250 100,000 10/25
No No No No No No No No N/A
40 40 100 15 10 40 ------4
No No No No No No No No No
1. Facility wide PTE is calculated by summing the maximum of scenarios 1a and 1b with the maximum of scenarios 2a and 2b, including fugitive emissions
2. Major source thresholds are defined by 40 CFR section 52.21(b)(1).
3. Modeling Limit is stated in UDAQ Emissions Impact Assessment Guidelines under Table 1: Total Controlled Emission Rates for New Sources or Emissions Increase.
Potential To Emit (tpy)
Major Source Thresholds2
Threshold Exceeded?
Modeling Limits3
Threshold Exceeded?
Scenario Description
Fugitives
Scenario
Number
Facility Wide PTE1
Scenario
Normal (VAV operational)
Emergency/Maintenance (VAV not operational)
GreenGasUSA 8/9/2024 Page 1 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-2. Average/Annual Potential HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b
2-Methylnaphthalene -1.11E-07 1.11E-07 4.32E-07 1.21E-03
3-Methylcholanthrene -8.36E-09 8.36E-09 3.24E-08 9.05E-05
7,12-Dimethylbenz(a)anthracene -7.43E-08 7.43E-08 2.88E-07 8.05E-04
Acenaphthene -8.36E-09 8.36E-09 3.24E-08 9.05E-05Acenaphthylene-8.36E-09 8.36E-09 3.24E-08 9.05E-05
Anthracene -1.11E-08 1.11E-08 4.32E-08 1.21E-04
Benz(a)anthracene -8.36E-09 8.36E-09 3.24E-08 9.05E-05
Benzene -9.76E-06 9.76E-06 3.78E-05 1.06E-01
Benzo(a)pyrene -5.57E-09 5.57E-09 2.16E-08 6.04E-05Benzo(b)fluoranthene -8.36E-09 8.36E-09 3.24E-08 9.05E-05
Benzo(g,h,i)perylene -5.57E-09 5.57E-09 2.16E-08 6.04E-05
Chrysene -8.36E-09 8.36E-09 3.24E-08 9.05E-05
Dibenzo(a,h) anthracene -5.57E-09 5.57E-09 2.16E-08 6.04E-05
Dichlorobenzene -5.57E-06 5.57E-06 2.16E-05 6.04E-02Fluoranthene-1.39E-08 1.39E-08 5.40E-08 1.51E-04
Fluorene -1.30E-08 1.30E-08 5.04E-08 1.41E-04
Formaldehyde -3.48E-04 3.48E-04 1.35E-03 3.77E+00
Hexane -8.36E-03 8.36E-03 3.24E-02 9.05E+01
Indeno(1,2,3-cd)pyrene -8.36E-09 8.36E-09 3.24E-08 9.05E-05Naphthalene-2.83E-06 2.83E-06 1.10E-05 3.07E-02
Phenanthrene -7.90E-08 7.90E-08 3.06E-07 8.55E-04
Pyrene -2.32E-08 2.32E-08 8.99E-08 2.52E-04
Toluene -1.58E-05 1.58E-05 6.12E-05 1.71E-01
H2S 0.1042 0.0021 0.0625 0.0594 882.98
1. The Emission Threshold Value (ETV) assumes <50 m distance to the fenceline and vertically unrestricted releases.
Table B-3. Maximum Hourly HAP Emissions
Scenario 1a Scenario 1b Scenario 2a Scenario 2b2-Methylnaphthalene -1.36E-07 1.36E-07 8.14E-07 8.14E-07 --No
3-Methylcholanthrene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --No
7,12-Dimethylbenz(a)anthracene -9.05E-08 9.05E-08 5.43E-07 5.43E-07 --No
Acenaphthene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --No
Acenaphthylene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --NoAnthracene-1.36E-08 1.36E-08 8.14E-08 8.14E-08 --No
Benz(a)anthracene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --No
Benzene -1.19E-05 1.19E-05 7.12E-05 7.12E-05 0.31627 No
Benzo(a)pyrene -6.79E-09 6.79E-09 4.07E-08 4.07E-08 --No
Benzo(b)fluoranthene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --NoBenzo(g,h,i)perylene -6.79E-09 6.79E-09 4.07E-08 4.07E-08 --No
Chrysene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --No
Dibenzo(a,h) anthracene -6.79E-09 6.79E-09 4.07E-08 4.07E-08 --No
Dichlorobenzene -6.79E-06 6.79E-06 4.07E-05 4.07E-05 --No
Fluoranthene -1.70E-08 1.70E-08 1.02E-07 1.02E-07 --NoFluorene-1.58E-08 1.58E-08 9.50E-08 9.50E-08 --No
Formaldehyde -4.24E-04 4.24E-04 2.54E-03 0.0025 0.05674 No
Hexane -1.02E-02 1.02E-02 6.10E-02 6.10E-02 34.895 No
Indeno(1,2,3-cd)pyrene -1.02E-08 1.02E-08 6.10E-08 6.10E-08 --No
Naphthalene -3.45E-06 3.45E-06 2.07E-05 2.07E-05 10.381 NoPhenanthrene-9.61E-08 9.61E-08 5.76E-07 5.76E-07 --No
Pyrene -2.83E-08 2.83E-08 1.70E-07 1.70E-07 --No
Toluene -1.92E-05 1.92E-05 1.15E-04 1.15E-04 14.9217 No
H2S 0.2154 0.0043 0.1293 0.1122 0.22 0.2760 No
Modeling
Required?
Total Emissions
(lb/yr)Project Hourly Emissions (lb/hr)
Pollutant Maximum Hourly Emissions (lb/hr)Maximum
Emissions (lb/hr)
Pollutant
ETV1
GreenGasUSA 8/9/2024 Page 2 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Table B-4. Operations
Scenario Scenario
Number
Scenario
Description Quantity Units Quantity Units
1a Treated Tail Gas
Emitted 335 days/yr 8,040 Hours/year
1b Treated Tail Gas
Combusted 335 days/yr 8,040 Hours/year
2a Untreated Tail
Gas Combusted 30 days/yr 720 Hours/year
2b Raw Gas
Combusted 30 days/yr 720 Hours/year
Table B-5. Raw and Tail Gas Information
Parameter
Raw (Pre-VAV
+ Molegate
PSA)
Tail (Post-VAV
+ Molegate
PSA)
Unit
H2S Concentration (treated)50 142.35 ppmv
H2S Concentration (untreated)1500 4270.5 ppmv
CH4 Concentration 70 10 %
CO2 Concentration 30 90 %
Gas Flow (average) 410 144 acfm
Gas Flow (Maximum) 775 262 acfm
Gas Pressure (actual)1 2 psig
Gas Pressure (Maximum)1 4 psig
Gas Temperature (actual)80 90 °F
Atmospheric pressure in Hyrum, UT 12.7 12.7 psia
Table B-6. Flare Pilot/Purge Gas Combustion Emissions - Controlled Operation
Parameter Value Unit
H2S Destruction Efficiency1 98%%
Pilot/Purge Gas Flow1 100 scf/hr
Enrichment Gas Flow (average)1 60 scfm
Enrichment Gas Flow (Maximum)1 112 scfm
Pilot/Purge Heat Content2 1,020 Btu/scf
Enrichment Gas Heat Content2 1,020 Btu/scf
2. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-7. Fugitive Source Parameters1
Equipment Type Quantity of
each (#)
Valves - Gas 30
Flanges - Gas 60
Compressor Seals - Gas 3
Relief Valves - Gas 15
Sampling Connection - Gas 3
1. Used to calculate fugitive emissions from connections in process equipment
Days/Yr Running Various Operations
Raw and Tail Gas Information
Flare Information
1. Pilot/purge gas volume based on manufacturer design.
Normal (VAV operational)
Emergency/Maintenance (VAV not
operational)
GreenGasUSA 8/9/2024 Page 3 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Emissions - Scenario 1
Table B-8. Treated Tail Gas Parameters
Annual Operation 8,040 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (Maximum)4.00 psig
Tail Gas Temperature (actual)549.67 °R
Tail Gas Flow (average - std conditions)1,2 9,455 scf/hr
Tail Gas Flow (Maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 142 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 psia
2. Conversion factors:
60 min/hr
Table B-9. Treated Tail Gas Composition
Pollutant H2S SO2 CH4 CO2
Concentration 0.014%0.000%10.00%90.00%
Average Flow Rate (scf/hr)1 1.35 0.00 945.48 8,509
Maximum Flow Rate (scf/hr)2 2.78 0.00 1954.30 17588.69
Concentration 0.0003%0.014%-90.00%
Average Flow Rate (scf/hr)1 0.03 1.32 -8509.33Maximum Flow Rate (scf/hr)2 0.06 2.73 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
1. Flow Rate (scf/hr) = Concentration (%) * Tail Gas Flow (scf/hr)
Table B-10. Secnario 1a - Emissions from Treated Tail Gas
Volume Flow Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow
Rate (scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 1.35 3.07E-03 0.10 0.42 2.78 6.34E-03 0.22 0.87
CO2 8509.33 19.38 852.76 3428.08 17588.69 40.06 1762.64 7085.79
CH4 945.48 2.15 34.45 138.51 1954.30 4.45 71.22 286.29
CO2e --1714.12 6890.78 --3543.07 14243.16
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-11. Scenario 1b - Emissions from Treated and Flared Tail Gas
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 0.03 6.13E-05 2.08E-03 8.38E-03 0.06 1.27E-04 4.31E-03 0.02
SO2 1.32 0.00 0.19 0.77 2.73 0.01 0.40 1.60
CO2 8509.33 19.38 852.76 3428.08 17588.69 40.06 640.96 2576.65
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressure 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempature) = 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
4. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Tail Gas Information
Average Flow Rates Maximum Flow Rates
After Flare (Scenario 1b)
Average Flow Rates Maximum Flow Rates
Before Flare (Scenario 1a)
Constituent
Constituent
GreenGasUSA 8/9/2024 Page 4 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Treated Tail Gas Flaring Emissions - Scenario 1b
Table B-12. Treated Tail Gas Flaring Parameters
Annual Operation 8040 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrEnrichment Gas Flow 3,600 scf/hrAverage Methane Gas Flow from
Tail Gas Stream2 945.48 scf/hr
Average Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Tail Gas Stream2 1954.30 scf/hr
Maximum Total Natural Gas Flow 5654.30 scf/hr
Natural Gas Higher Heating Value
(HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-13. Treated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual Emissions
(tpy)
Hourly
Emissions4
(lb/hr)
Annual Emissions
(tpy)
NOX 0.1380 lb/MMBtu 6.54E-01 2.63E+00 7.96E-01 3.20E+00
CO 0.31 lb/MMBtu 1.47E+00 5.90 1.79E+00 7.19VOC 0.66 lb/MMBtu 3.13E+00 12.57 3.81E+00 15.30
PM 7.60 lb/MMscf 3.53E-02 1.42E-01 4.30E-02 1.73E-01PM (con)5.70 lb/MMscf 2.65E-02 1.06E-01 3.22E-02 1.30E-01PM (fil)1.90 lb/MMscf 8.83E-03 3.55E-02 1.07E-02 4.32E-02
SO2 0.60 lb/MMscf 2.79E-03 1.12E-02 3.39E-03 1.36E-02
CO25 119316.82 lb/MMscf 5.54E+02 2.23E+03 6.75E+02 2.71E+03
CH45 2.25 lb/MMscf 1.04E-02 4.20E-02 1.27E-02 5.11E-02
N2O5 0.22 lb/MMscf 1.04E-03 4.20E-03 1.27E-03 5.11E-03
CO2e6 119440.05 lb/MMscf 5.55E+02 2.23E+03 6.75E+02 2.71E+03
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-14. Treated Tail Gas Flaring HAP Emission Factors
Hourly
Emission
Annual
Emissions
Hourly
Emission
Annual
EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)Benzene 2.10E-03 lb/MMscf 9.76E-06 3.92E-05 1.19E-05 4.77E-05
2-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.48E-07 1.36E-07 5.46E-07
3-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-087,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 2.99E-07 9.05E-08 3.64E-07
Acenaphthene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-08Acenaphthylene1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-08
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.48E-08 1.36E-08 5.46E-08
Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-08Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 6.79E-09 2.73E-08
Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-08Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 6.79E-09 2.73E-08
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.24E-08 6.79E-09 2.73E-08Dichlorobenzene1.20E-03 lb/MMscf 5.57E-06 2.24E-05 6.79E-06 2.73E-05
Fluoranthene 3.00E-06 lb/MMscf 1.39E-08 5.60E-08 1.70E-08 6.82E-08Fluorene2.80E-06 lb/MMscf 1.30E-08 5.23E-08 1.58E-08 6.36E-08
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.40E-03 4.24E-04 1.70E-03
Hexane 1.8 lb/MMscf 8.36E-03 3.36E-02 1.02E-02 4.09E-02Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.36E-08 1.02E-08 4.09E-08
Naphthalene 6.10E-04 lb/MMscf 2.83E-06 1.14E-05 3.45E-06 1.39E-05Phenanthrene1.70E-05 lb/MMscf 7.90E-08 3.17E-07 9.61E-08 3.86E-07
Pyrene 5.00E-06 lb/MMscf 2.32E-08 9.34E-08 2.83E-08 1.14E-07
Toluene 3.40E-03 lb/MMscf 1.58E-05 6.35E-05 1.92E-05 7.73E-058.74E-03 3.52E-02 1.06E-02 4.28E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Total HAPs
Flare Information
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Pollutant Emission Factor1
GreenGasUSA 8/9/2024 Page 5 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Untreated and Flared Tail Gas - Scenario 2a
Table B-15. Untreated Tail Gas Parameters
Annual Operation 720 hrs/yr
Tail Gas Flow (average)144 acf/min
Tail Gas Flow (maximum)262 acf/min
Tail Gas Pressure (average)2.00 psig
Tail Gas Pressure (Maximum)4.00 psig
Tail gas Temperature (actual)549.67 °R
Tail Gas Flow (average - std conditions) 1,2 9,455 scf/hr
Tail Gas Flow (Maximum - std conditions)1,2 19,543 scf/hrH2S Concentration 4,271 ppmv
1. Tail Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 pisa
2. Conversion factors:
60 min/hr
Table B-16. Untreated Tail Gas Composition
H2S SO2 CH4 CO2
Concentration1,2 (%)0.427%0.000%10.00%90.00%
Average Flow Rate3 (scf/hr)40.38 0.00 945.48 8509.33
Maximum Flow Rate3 (scf/hr)83.46 0.00 1954.30 17588.69
Concentration1,2 (%)0.0085%0.419%-90.00%
Average Flow Rate3 (scf/hr)0.81 39.57 -8509.33Maximum Flow Rate3 (scf/hr)1.67 81.79 -17588.69
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted. See emissons from CH4 combustion on next page.
3. Flow Rate (scf/hr) = Concentration (%) * Raw Gas Flow (std conditions)(scf/hr)
Table B-17. Untreated Tail Gas Combusted Emissions
Volume Flow
Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume
Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)H2S 0.81 1.84E-03 0.06 0.02 1.67 3.80E-03 0.13 0.05
SO2 39.57 0.09 5.77 2.08 81.79 1.86E-01 11.92 4.29
CO2 8509.33 19.38 852.76 306.99 17588.69 4.01E+01 1762.64 634.55
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressur 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempatur 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
Average Flow Rates Maximum Flow Rates
Constituent
Tail Gas Information
Before Flare
After Flare
GreenGasUSA 8/9/2024 Page 6 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Untreated Tail Gas - Scenario 2a
Table B-18. Untreated Tail Gas Flaring Parameters
Annual Operation 720 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrEnrichment Gas Flow 3,600 scf/hrAverage Methane Gas Flow from Untreated
Tail Gas Stream2 945.48 scf/hr
Average Total Natural Gas Flow 4645.48 scf/hrMaximum Methane Gas Flow from
Untreated Tail Gas Stream2 1954.30 scf/hrMaximum Total Natural Gas Flow 5654.30 scf/hr
Natural Gas Higher Heating Value (HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of tail gas stream is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-19. Untreated Tail Gas Flaring Criteria and GHG Emissions
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
Hourly
Emissions4
(lb/hr)
Annual
Emissions
(tpy)
NOX 0.1380 lb/MMBtu 6.54E-01 2.35E-01 7.96E-01 2.87E-01
CO 0.31 lb/MMBtu 1.47E+00 0.53 1.79E+00 0.64VOC 0.66 lb/MMBtu 3.13E+00 1.13 3.81E+00 1.37PM7.60 lb/MMscf 3.53E-02 1.27E-02 4.30E-02 1.55E-02PM (con)5.70 lb/MMscf 2.65E-02 0.01 3.22E-02 0.01PM (fil)1.90 lb/MMscf 8.83E-03 0.00 1.07E-02 0.00
SO2 0.60 lb/MMscf 2.79E-03 1.00E-03 3.39E-03 1.22E-03
CO25 119316.82 lb/MMscf 5.54E+02 199.54 6.75E+02 2.43E+02
CH45 2.25 lb/MMscf 1.04E-02 3.76E-03 1.27E-02 4.58E-03
N2O5 0.22 lb/MMscf 1.04E-03 3.76E-04 1.27E-03 0.00
CO2e6 119440.05 lb/MMscf 5.55E+02 200 6.75E+02 243
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-20. Misc. Natural Gas HAP Emission Factors
Hourly
Emission
Annual
Emissions
Hourly
Emission
Annual
EmissionsValueUnit(lb/hr)(tpy)(lb/hr)(tpy)
Benzene 2.10E-03 lb/MMscf 9.76E-06 3.51E-06 1.19E-05 4.27E-062-Methylnaphthalene 2.40E-05 lb/MMscf 1.11E-07 4.01E-08 1.36E-07 4.89E-08
3-Methylcholanthrene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-097,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 7.43E-08 2.68E-08 9.05E-08 3.26E-08
Acenaphthene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-09Acenaphthylene1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-09
Anthracene 2.40E-06 lb/MMscf 1.11E-08 4.01E-09 1.36E-08 4.89E-09
Benz(a)anthracene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-09
Benzo(a)pyrene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 6.79E-09 2.44E-09Benzo(b)fluoranthene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-09
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 6.79E-09 2.44E-09
Chrysene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-09
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 5.57E-09 2.01E-09 6.79E-09 2.44E-09Dichlorobenzene1.20E-03 lb/MMscf 5.57E-06 2.01E-06 6.79E-06 2.44E-06
Fluoranthene 3.00E-06 lb/MMscf 1.39E-08 5.02E-09 1.70E-08 6.11E-09
Fluorene 2.80E-06 lb/MMscf 1.30E-08 4.68E-09 1.58E-08 5.70E-09
Formaldehyde 7.50E-02 lb/MMscf 3.48E-04 1.25E-04 4.24E-04 1.53E-04Hexane1.8 lb/MMscf 8.36E-03 3.01E-03 1.02E-02 3.66E-03
Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 8.36E-09 3.01E-09 1.02E-08 3.66E-09
Naphthalene 6.10E-04 lb/MMscf 2.83E-06 1.02E-06 3.45E-06 1.24E-06
Phenanthrene 1.70E-05 lb/MMscf 7.90E-08 2.84E-08 9.61E-08 3.46E-08
Pyrene 5.00E-06 lb/MMscf 2.32E-08 8.36E-09 2.83E-08 1.02E-08
Toluene 3.40E-03 lb/MMscf 1.58E-05 5.69E-06 1.92E-05 6.92E-06
8.74E-03 3.15E-03 1.06E-02 3.83E-03
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Total HAPs
Flare Information
Pollutant Emission Factor1
Average Natural Gas Flow
GreenGasUSA 8/9/2024 Page 7 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Raw Gas - Scenario 2b
Table B-21. Raw Gas Parameters
Annual Operation 720 hrs/yr
Average Raw Gas Flow 410 acf/minMaximum Raw Gas Flow 775 acf/min
Raw Gas Pressure 1.00 psig
Raw Gas Temperature (actual)539.67 °R
Average Raw Gas Flow (std conditions) 1,2 25,554 scf/hr
Maximum Raw Gas Flow (std conditions) 1,3 48,302 scf/hr
H2S Concentration 1,500 ppmv
1. Raw Gas flow at standard conditions calculated using ideal gas law:
Vact = Vstd * (Pstd / Pact) * (Tact / Tstd)
Vstd = Vact * (Pact / Pstd) * (Tstd / Tact)
where
Temp (std) =519.67 oR
Pressure (std) =12.7 pisa
2. Conversion factors:
60 min/hr
Table B-22. Raw Gas Composition
H2S SO2 CH4 CO2
Concentration1,2 (%)0.150%0.000%70.00%30.00%
Average Flow Rate3 (scf/hr)38.33 0.00 17887.49 7666.07Maximum Flow Rate3 (scf/hr)72.45 0.00 33811.72 14490.74
Concentration1,2 (%)0.0030%0.147%-30.00%
Average Flow Rate3 (scf/hr)0.77 37.56 -7666.07
Maximum Flow Rate3 (scf/hr)1.45 71.00 -14490.74
1. H2S converted to SO2, flare destruction efficency of:98%
2. CH4 is combusted, CO2 is not combusted.See emissons from CH4 combustion on next page.
3. Flow Rate (scf/hr) = Concentration (%) * Raw Gas Flow (std conditions)(scf/hr)
Table B-23. Emissions from Raw Gas Combustion
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
Volume Flow Rate
(scf/hr)
Molar Flow
Rate1
(lbmol/hr)
Hourly
Emissions2
(lb/hr)
Annual
Emissions3,4
(tpy)
H2S 0.77 1.75E-03 0.06 0.02 1.45 3.30E-03 0.11 0.04
SO2 37.56 0.09 5.48 1.97 71.00 0.16 10.35 3.73
CO2 7666.07 17.46 768.25 276.57 14490.74 33.00 1452.18 522.78
1. Per TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
m=((MW) * (P*V))/(R*T)
where,m= mass flow rate (lb/hr)
MW= molecular weight (lb/lb-mole)
Hydrogen Sulfide =34
Sulfur Dioxide =64
Methane =16
Carbon Dioxide =44
P = standard pressur 12.7 psia
V = flow rate (scf/hr)
R (gas constant) =10.73 psia.ft3.lbmol-1.°R-1
T (standard tempatu 519.67 °R
2. Emissions(lb/hr) calculated are equal to (H2S Molar Flow lbmol/hr) * (H2S Molecular Weight)
3. Annual emissions (tpy) are are calculated as (lb H2S/hr) * (hr/yr) / (2000 lb/ton).
Average Flow Rates Maximum Flow Rates
Constituent
Raw Gas Information
Before Flare
After Flare
GreenGasUSA 8/9/2024 Page 8 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Emissions from Flaring of Raw Gas - Scenario 2b
Table B-24. Natural Gas Parameters
Annual Operation 720 hr/yr
Pilot/Purge Gas Flow1 100 scf/hrAverage Methane Gas Flow from Raw Gas
Stream2 17887.49 scf/hrAverage Total Natural Gas Flow 17987.49 scf/hrMaximum Methane Gas Flow from Raw
Gas Stream2 33811.72 scf/hrMaximum Total Natural Gas Flow 33911.72 scf/hr
Natural Gas Higher Heating Value (HHV)3 1,020 Btu/scf
1. Pilot/purge natural gas volume based on manufacturer design.
2. Methane portion of raw gas is combusted. Emissions are calculated using natural gas emission factors.
3. Average heating value of natural gas per U.S. AP-42 Chapter 1.4 Natural Gas Combustion (July 1998).
Table B-25. Emissions from Natural Gas
Hourly
Emissions4
(lb/hr)
Annual Emissions (tpy)
Hourly
Emissions4
(lb/hr)
Annual Emissions (tpy)
NOX 0.1380 lb/MMBtu 2.53E+00 0.91 4.77E+00 1.72
CO 0.31 lb/MMBtu 5.69E+00 2.05 1.07E+01 3.86
VOC 0.66 lb/MMBtu 1.21E+01 4.36 2.28E+01 8.22PM7.60 lb/MMscf 1.37E-01 0.05 2.58E-01 0.09PM (con)5.70 lb/MMscf 1.03E-01 0.04 1.93E-01 0.07PM (fil)1.90 lb/MMscf 3.42E-02 0.01 6.44E-02 0.02SO20.60 lb/MMscf 1.08E-02 0.00 2.03E-02 0.01
CO25 119316.82 lb/MMscf 2.15E+03 773 4.05E+03 1,457
CH45 2.25 lb/MMscf 4.04E-02 0.01 7.63E-02 0.03
N2O5 0.22 lb/MMscf 4.04E-03 0.00 7.63E-03 0.00
CO2e6 119440.05 lb/MMscf 2.15E+03 773 4.05E+03 1,458
1. NOx Emission Factor from TCEQ Air Permit Technical Guidance for Chemical Sources: Flares and Vapor Oxidizers (APD-ID 6v1, March 2021).
2. CO and VOC Emission Factor from AP-42 Chapter 13.5 'Industrial Flares', Table 13.5-2.
3. PM and SO2 Emission Factor from AP-42 Section 1.4 Table 1.4-2
4. Emissions are calculated as (Emission Factor) * (Gross Heating Value) * (Pilot gas Flow) / (Conversion Factor). Annual emissions are converted to tons per year.
Conversion factor (MMbase unit):1 MMbase unit=1000000 Base Unit
5. Emission factors from 40 CFR 98 Tables C-1 and C-2 (kg/MMBtu):
53.06 CO2
1.00E-03 CH4
1.00E-04 N2O
6. CO2e is the sum of GHG constituents multiplied by their respective global warming potential per 40 CFR 98 Table A-1.
1 CO2 GWP
25 CH4 GWP
298 N2O GWP
Table B-26. Misc. Natural Gas HAP Emission Factors
Hourly Annual Hourly Annual Value Unit (lb/hr)(tpy)(lb/hr)(tpy)
Benzene 2.10E-03 lb/MMscf 3.78E-05 1.36E-05 7.12E-05 2.56E-05
2-Methylnaphthalene 2.40E-05 lb/MMscf 4.32E-07 1.55E-07 8.14E-07 2.93E-073-Methylcholanthrene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf 2.88E-07 1.04E-07 5.43E-07 1.95E-07
Acenaphthene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Acenaphthylene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Anthracene 2.40E-06 lb/MMscf 4.32E-08 1.55E-08 8.14E-08 2.93E-08
Benz(a)anthracene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Benzo(a)pyrene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Benzo(b)fluoranthene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Benzo(g,h,i)perylene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Chrysene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08
Dibenzo(a,h) anthracene 1.20E-06 lb/MMscf 2.16E-08 7.77E-09 4.07E-08 1.46E-08
Dichlorobenzene 1.20E-03 lb/MMscf 2.16E-05 7.77E-06 4.07E-05 1.46E-05
Fluoranthene 3.00E-06 lb/MMscf 5.40E-08 1.94E-08 1.02E-07 3.66E-08Fluorene2.80E-06 lb/MMscf 5.04E-08 1.81E-08 9.50E-08 3.42E-08
Formaldehyde 7.50E-02 lb/MMscf 1.35E-03 4.86E-04 2.54E-03 9.16E-04
Hexane 1.8 lb/MMscf 3.24E-02 1.17E-02 6.10E-02 2.20E-02Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf 3.24E-08 1.17E-08 6.10E-08 2.20E-08Naphthalene6.10E-04 lb/MMscf 1.10E-05 3.95E-06 2.07E-05 7.45E-06
Phenanthrene 1.70E-05 lb/MMscf 3.06E-07 1.10E-07 5.76E-07 2.08E-07
Pyrene 5.00E-06 lb/MMscf 8.99E-08 3.24E-08 1.70E-07 6.10E-08
Toluene 3.40E-03 lb/MMscf 6.12E-05 2.20E-05 1.15E-04 4.15E-05
3.39E-02 1.22E-02 6.38E-02 2.30E-02
1. Emission factors from AP-42 Section 1.4 Table 1.4-3 for natural gas combustion
Maximum Natural Gas Flow
Pollutant Emission Factor 1,2,3
Average Natural Gas Flow Maximum Natural Gas Flow
Total HAPs
Flare Information
Pollutant Natural Gas1
Average Natural Gas Flow
GreenGasUSA 8/9/2024 Page 9 of 10
GreenGasUSA Hyrum, UT RNG Facility Emission Calculations
Fugitive emissions
Table B-27. Fugitive Emission Factors Table B-28. Speciated Gas Components
Component wt%1
H2S wt%0.15%
(lb/hr/source)CO2 wt%30.00%
Valves - Gas 0.01320 30 CH4 wt%70.00%
Flanges - Gas 0.00390 60 1. Raw gas composition used for fugitive calculations
Compressor Seals - Gas 0.50270 3
Relief Valves - Gas 0.22930 15
Sampling Connection - Gas 0.03300 3
Table B-29. Emission Rates for CO2 and CH4
(lb/hr)(tpy)(lb/hr)(tpy)(lb/hr)(tpy)Valves - Gas 0.12 0.52 0.28 1.21 7.05 30.87Flanges - Gas 0.07 0.31 0.16 0.72 4.17 18.24Compressor Seals - Gas 0.45 1.98 1.06 4.62 26.84 117.58Relief Valves - Gas 1.03 4.52 2.41 10.55 61.22 268.16
Other - Gas 0.03 0.13 0.07 0.30 1.76 7.72
Total 1.70 7.46 3.97 17.40 101.04 442.57
1. Hours of operations:8760
2. Global Warming Potential of CH4 from 40 CFR 98 Table A-1 25
Table B-30. Emission Rate for H2S
(lb/hr)(tpy)Valves - Gas 5.94E-04 2.60E-03Flanges - Gas 3.51E-04 1.54E-03Compressor Seals - Gas 2.26E-03 9.91E-03Relief Valves - Gas 5.16E-03 0.02
Other - Gas 1.49E-04 6.50E-04
Total 0.01 0.04
H2S Emission RateEquipment Type
Equipment Type CO2e Emission Rate1,2
Equipment Type
Uncontrolled
Emission
Factor1 Source
Count
1. Factors are from TCEQ Air Permit Technical Guidance for Chemical Sources: Fugitive Guidance. Emission Factors - Oil and Gas Production
Operations, June 2018.
CO2 Emission Rate CH4 Emission Rate
GreenGasUSA 8/9/2024 Page 10 of 10